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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 March 31, 2015
 
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 May 4, 2015, the registrant has 23,800,943 common units outstanding, 12,213,713 subordinated units outstanding and 15,414,754 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

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 March 31, 2015 and December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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 section entitled “Risk Factors” included in our 2014 Annual Report on Form 10-K.
 
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by these risks and uncertainties. These risks and uncertainties include, among others:
 
the volatility of natural gas, crude oil and NGL prices and the price and demand of products derived from these commodities, particularly in the depressed energy price environment that began in the second half of 2014, which has the potential for further deterioration and may result in a material reduction in exploration, development and production;
competitive conditions in our industry and the extent and success of producers increasing production or replacing declining production and our success in obtaining new sources of supply;
industry conditions and supply of pipelines, processing and fractionation capacity relative to available natural gas from producers;
our dependence upon a relatively limited number of customers for a significant portion of our revenues;
actions taken or inactions or 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 certain gathering and processing assets from TexStar Midstream Services, LP in August 2014;
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, and the potential for lack of access to debt capital markets if the depressed energy price environment that began in the second half of 2014 continues;
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.
 

4


The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this report may not, in fact, occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to 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)
 
March 31, 2015
 
December 31, 2014
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
230

 
$
1,649

Trade accounts receivable
54,654

 
71,159

Accounts receivable - affiliates
8,882

 
11,325

Prepaid expenses
2,423

 
3,073

Other current assets
750

 
1,813

Total current assets
66,939

 
89,019


 
 
 
Property, plant and equipment, net
971,615

 
968,810

Intangible assets, net
1,497

 
1,511

Investments in joint ventures
145,675

 
147,098

Other assets
16,275

 
17,189

Total assets
$
1,202,001

 
$
1,223,627

 
 
 
 
LIABILITIES AND PARTNERS’ CAPITAL
 
 
 
Current liabilities:
 
 
 

Accounts payable and accrued liabilities
$
76,938

 
$
103,188

Accounts payable - affiliates
3,803

 
12,856

Current portion of long-term debt
4,500

 
4,500

Other current liabilities
14,005

 
11,061

Total current liabilities
99,246

 
131,605



 

Long-term debt
505,092

 
471,129

Other non-current liabilities
1,392

 
1,109

Total liabilities
605,730

 
603,843

 
 
 
 
Commitments and contingencies (Note 7)
 
 
 
 
 
 
 
Partners' capital:
 
 
 
Common units (23,800,943 units outstanding as of March 31, 2015 and December 31, 2014)
243,464

 
259,735

Class B Convertible units (15,149,636 and 14,889,078 units issued and outstanding as of March 31, 2015 and December 31, 2014, respectively)
299,426

 
298,833

Subordinated units (12,213,713 units issued and outstanding as of March 31, 2015 and December 31, 2014)
41,628

 
48,831

General partner interest
11,753

 
12,385

Total partners' capital
596,271

 
619,784

Total liabilities and partners' capital
$
1,202,001

 
$
1,223,627

 
See accompanying notes.

6


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for per unit data)
(Unaudited)
 
 
Three Months Ended March 31,
 
2015
 
2014
Revenues:
 
 
 
Revenues
$
173,102

 
$
213,591

Revenues - affiliates
7,447

 

Total revenues
180,549

 
213,591

 
 
 
 
Expenses:
 

 
 
Cost of natural gas and liquids sold
141,115

 
186,403

Operations and maintenance
17,190

 
10,861

Depreciation and amortization
13,953

 
8,528

General and administrative
7,705

 
6,103

Loss on sale of assets, net
218

 
4

Total expenses
180,181

 
211,899

 
 
 
 
Income from operations
368

 
1,692

Other income (expense):


 


Equity in losses of joint venture investments
(3,552
)
 

Interest expense
(7,498
)
 
(2,973
)
Total other expense
(11,050
)
 
(2,973
)
Loss before income tax expense
(10,682
)
 
(1,281
)
Income tax expense
(69
)
 
(8
)
Net loss
$
(10,751
)
 
$
(1,289
)
Series A Preferred Unit fair value adjustment

 
33

Series A Preferred Unit in-kind distribution

 
(534
)
General partner Unit in-kind distribution
(76
)
 

Net loss attributable to partners
$
(10,827
)
 
$
(1,790
)
 
 
 
 
Earnings per unit and distributions declared
 
 
 
Net loss allocated to limited partner common units
$
(4,936
)
 
$
(1,045
)
Weighted average number of limited partner common units outstanding
23,801

 
18,285

Basic and diluted loss per common unit
$
(0.21
)
 
$
(0.06
)
 
 
 
 
Net loss allocated to limited partner subordinated units
$
(2,533
)
 
$
(719
)
Weighted average number of limited partner subordinated units outstanding
12,214

 
12,214

Basic and diluted loss per subordinated unit
$
(0.21
)
 
$
(0.06
)
Distributions declared per common unit
$
0.40

 
$
0.40

 
See accompanying notes.

7


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
(Unaudited)
 
 
Three Months Ended March 31,
 
2015
 
2014
Net loss
$
(10,751
)
 
$
(1,289
)
Other comprehensive loss:
 

 
 

Hedging losses reclassified to earnings and recognized in interest expense

 
115

Adjustment in fair value of derivatives

 
(11
)
Total other comprehensive income

 
104

Comprehensive loss
$
(10,751
)
 
$
(1,185
)
 
See accompanying notes.

8


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited) 
 
Three Months Ended March 31,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net loss
$
(10,751
)
 
$
(1,289
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation and amortization
13,953

 
8,528

Unit-based compensation
813

 
529

Amortization of deferred financing costs
825

 
337

Loss on sale of assets, net
218

 
4

Unrealized loss (gain) on financial instruments
167

 
(32
)
Equity in losses of joint venture investments
3,552

 

Other, net
18

 
14

Changes in operating assets and liabilities:
 
 
 
Trade accounts receivable, including affiliates
19,082

 
(7,477
)
Prepaid expenses and other current assets
(297
)
 
813

Other non-current assets
170

 
(25
)
Accounts payable and accrued liabilities
(27,111
)
 
13,694

Other liabilities, including affiliates
2,789

 
(920
)
Net cash provided by operating activities
3,428

 
14,176

Cash flows from investing activities:

 
 
Capital expenditures
(27,772
)
 
(11,087
)
Expenditures for assets subject to property damage claims, net of insurance proceeds and deductibles
545

 
(693
)
Proceeds from sales of assets
4,368

 

Investment contribution to joint venture investments
(2,349
)
 

Other acquisitions

 
(38,636
)
Net cash used in investing activities
(25,208
)
 
(50,416
)
Cash flows from financing activities:


 
 
Proceeds from issuance of common units, net

 
144,715

Borrowings under our credit facility
50,000

 
62,000

Repayments under our credit facility
(15,000
)
 
(158,450
)
Repayments under our term loan agreement
(1,125
)
 

Payments on capital lease obligations
(140
)
 
(143
)
Financing costs
(6
)
 
(156
)
Contributions from general partner

 
3,115

Payments of distributions and distribution equivalent rights
(13,368
)
 
(13,755
)
Other, net

 
(1
)
Net cash provided by financing activities
20,361

 
37,325

 
 
 
 
Net (decrease) increase in cash and cash equivalents
(1,419
)
 
1,085

Cash and cash equivalents — Beginning of period
1,649

 
3,349

Cash and cash equivalents — End of period
$
230

 
$
4,434


See accompanying notes.

9


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

 
Partners' Capital



 
Limited Partners






Common

Class B Convertible
 
Subordinated

General Partner

Total
BALANCE - December 31, 2014
$
259,735

 
$
298,833

 
$
48,831

 
$
12,385

 
$
619,784

Net loss

(4,902
)
 
(3,119
)
 
(2,513
)
 
(217
)
 
(10,751
)
Class B Convertible unit in-kind distribution

(2,405
)
 
3,712

 
(1,232
)
 
(75
)
 

Unit-based compensation on long-term incentive plan

948

 

 

 

 
948

Cash distributions and distribution equivalent rights paid

(9,520
)
 

 
(3,432
)
 
(416
)
 
(13,368
)
Accrued distribution equivalent rights on long-term incentive plan

(342
)
 

 

 

 
(342
)
General partner unit in-kind distribution
 
(50
)
 

 
(26
)
 
76

 

BALANCE - March 31, 2015
$
243,464

 
$
299,426

 
$
41,628

 
$
11,753

 
$
596,271


 
 
Partners' Capital
 
 
 
 
Limited Partners
 
 
 
Accumulated Other Comprehensive Loss
 
 
 
 
Common
 
Subordinated
 
General Partner
 
 
Total
BALANCE - December 31, 2013
 
$
169,141

 
$
99,726

 
$
6,367

 
$
(210
)
 
$
275,024

Net loss
 
(757
)
 
(506
)
 
(26
)
 

 
(1,289
)
Issuance of common units, net
 
144,715

 

 

 

 
144,715

Unit-based compensation on long-term incentive plan
 
432

 

 

 

 
432

Series A convertible preferred unit in-kind distribution and fair value adjustment
 
(281
)
 
(210
)
 
(11
)
 

 
(502
)
Contributions from general partner
 

 

 
3,115

 

 
3,115

Cash distributions paid
 
(8,581
)
 
(4,885
)
 
(289
)
 

 
(13,755
)
Accrued distribution equivalent rights on long-term incentive plan
 
(76
)
 

 

 

 
(76
)
Tax withholdings on unit-based compensation vested units
 
(1
)
 

 

 

 
(1
)
General partner unit in-kind distribution
 
(6
)
 
(5
)
 
11

 

 

Net effect of cash flow hedges
 

 

 

 
104

 
104

BALANCE - March 31, 2014
 
$
304,586

 
$
94,120

 
$
9,167

 
$
(106
)
 
$
407,767


See accompanying notes.

10


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 and a portion of our common units. Southcross Energy LLC is controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”).

Holdings Transaction

On August 4, 2014, Southcross Energy LLC and TexStar Midstream Services, LP, a Texas limited partnership (“TexStar”), combined pursuant to a contribution agreement in which Southcross Holdings LP, a Delaware limited partnership (“Holdings”), was formed (the “Holdings Transaction”). As a result of the Holdings Transaction, Holdings indirectly owns 100% of our General Partner (and therefore controls us), all of our subordinated units and a portion of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights. Charlesbank, EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services also own certain additional equity interests in Holdings.

TexStar Rich Gas System Transaction

Contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us certain gathering and processing assets (the “TexStar Rich Gas System”), which were owned by TexStar (the “TexStar Rich Gas System Transaction”). For additional details regarding the Holdings Transaction and the TexStar Rich Gas System Transaction, see Notes 2, 6, 9, 10, and 13.

Liquidity Consideration
Beginning in the second half of 2014 and continuing through the issuance of our financial statements, commodity prices have experienced increased volatility. In particular, natural gas, crude oil and NGL prices have decreased significantly. If a material reduction in drilling occurs in the geographic areas in which we operate, including the Eagle Ford Shale region, or significant, prolonged pricing deterioration occurs for commodities we sell, our future cash flow may be materially adversely affected.
The majority of our revenue is derived from fixed-fee contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than the value of the underlying natural gas or NGLs, although a percentage of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity.
After considering these uncertainties and in developing our annual budget for 2015, our forecast indicates a potential shortfall in the amount of consolidated EBITDA (as defined in our Credit Facility (as defined in Note 6)) to comply with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 6) in our Credit Facility. As discussed in further detail in Note 6, we have the right (which cannot be exercised more than two times in any 12-month period or more than four times during the term of the facility) to cure such a Financial Covenant Default (as defined in Note 6) by our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we would also experience a cross default under our Term Loan Agreement (defined in Note 6) and all of our debt would become due and payable to our lenders.

11


In response to the Partnership’s expected need for additional liquidity, our Sponsors (as defined in Note 10) have committed to provide the necessary funding to support the Partnership for at least a reasonable period of time in an amount up to $25 million to ensure the Partnership has sufficient liquidity to comply with its applicable Financial Covenants, and to fund normal operating and growth capital requirements. Therefore, our financial statements have been presented as if the Partnership will continue as a going concern. See Notes 6 and 15.
Description of Business
We are a master limited partnership that provides natural gas gathering, processing, treating, compression and transportation services and NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our assets are located in South Texas, Mississippi and Alabama and include four gas processing plants, two fractionation facilities and our pipelines. We are headquartered in Dallas, Texas.
Segments
Our chief operating decision maker is our General Partner’s Chief Executive Officer, who reviews financial information presented on a consolidated basis in order to assess our performance and make decisions about resource allocations. There are no segment managers who are held accountable by the chief operating decision maker, or anyone else, for operations, operating results and planning for levels or components below the consolidated unit level. Accordingly, we have determined that we have one reportable segment.
 
Basis of Presentation
 
We prepared this report under the rules and regulations of the Securities and Exchange Commission and in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements. Accordingly, these condensed consolidated financial statements do not include all of the disclosures required by GAAP and should be read in conjunction with our 2014 Annual Report on Form 10-K. The condensed consolidated financial statements as of March 31, 2015 and December 31, 2014, and for the three months ended March 31, 2015 and 2014, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2014 Annual Report on Form 10-K. Adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations and financial position have been included herein. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements.

The condensed consolidated financial statements reflect the assets acquired and liabilities assumed and the related operating results associated with (i) the Onyx pipelines acquisition beginning on March 6, 2014, (ii) the TexStar Rich Gas System Transaction beginning on August 4, 2014, (iii) and the Texoz acquisition beginning on November 21, 2014. See Note 2.

As a result of the Holdings Transaction, Holdings acquired a controlling equity interest in the Partnership, which was accounted for under the acquisition method of accounting in the consolidated financial statements of Holdings, whereby Holdings recorded the Partnership’s assets acquired and liabilities assumed at fair value.

Additionally, because the TexStar Rich Gas System was owned by TexStar, the Partnership recorded the TexStar Rich Gas System at TexStar’s historical cost. Thus, the difference between consideration paid and the TexStar Rich Gas System’s historical cost (net book value) at August 4, 2014, the date on which the Holdings Transaction and the TexStar Rich Gas System Transaction closed, was recorded as a reduction to partners’ capital. Management concluded that the Partnership was the predecessor for accounting purposes for periods prior to August 4, 2014.
 
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 2014 Annual Report on Form 10-K.
 
We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed in this report.
 

12


Significant Accounting Policies
 
During the first quarter of 2015, there were no material changes to our significant accounting policies described in Note 1 of our 2014 Annual Report on Form 10-K.
 
Recent Accounting Pronouncements
 
Accounting standard-setting organizations frequently issue new or revised accounting rules. We review new pronouncements to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements.

In 2014, a comprehensive new revenue recognition standard that will supersede substantially all existing revenue recognition guidance under GAAP was issued. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers and in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are currently required to adopt this standard beginning in the first quarter of 2017. On April 1, 2015, the Financial Accounting Standards Board (“FASB”) voted to propose to defer the effective date of the new revenue recognition standard by one year. The FASB plans to disclose its decisions for a 30-day public comment period in a proposed Accounting Standards Update (“ASU”), which is expected to be issued during the second quarter of 2015.

In February 2015, the FASB issued an ASU that amended current consolidation guidance with regard to variable interest entities and voting interest entities. All reporting entities will need to re-evaluate and potentially revise their disclosures regarding this topic. This standard will become effective beginning in 2016.

2. ACQUISITIONS

TexStar Rich Gas System Transaction. On August 4, 2014, contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us the TexStar Rich Gas System through a contribution of TexStar’s equity interest in the entities that own the TexStar Rich Gas System (the “Contribution”). In exchange for the Contribution, we paid $80 million in cash, assumed $100 million of debt (which was immediately repaid through our Term Loan Agreement (as defined in Note 6)) and issued 14,633,000 Class B Convertible Units (the “Class B Convertible Units”). The TexStar Rich Gas System consists of a cryogenic processing plant, located in Bee County, Texas, and joint venture ownership in natural gas gathering and residue pipelines across the core producing areas extending from Dimmit to Karnes Counties, Texas in the liquids-rich window of the Eagle Ford Shale region. These pipelines are operated under split-capacity arrangements within joint venture arrangements with Targa Pipeline Partners LP (see Note 13).


13


The amount of the consideration paid over TexStar’s net book value of the assets received and liabilities assumed of the TexStar Rich Gas System was recorded as a reduction to partners’ capital as summarized as follows (in thousands):
Consideration paid (1)
 
$
404,414

Current assets
 
$
1,295

Property, plant and equipment, net
 
255,220

Investments in joint ventures(2)
 
152,050

Total assets contributed
 
408,565

Total liabilities assumed (3)
 
(102,776
)
Net identifiable assets contributed
 
$
305,789

Consideration paid in excess of net assets contributed
 
$
98,625

Allocation of reduction to partners' capital:
 
 
Common limited partner interest
$
45,420

 
Class B Convertible limited partner interest
27,925

 
Subordinated limited partner interest
23,308

 
General Partner interest
1,972

 
Total reduction to partners' capital
 
$
98,625

 
(1) This amount was calculated as follows: $80 million of cash plus 14,633,000 Class B Convertible Units at an issue price of $22.17, the closing price of the Partnership’s common units on August 4, 2014.
(2) Significant assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. See Note 13.
(3) This amount includes $100 million of debt assumed.
  
Onyx Pipelines Acquisition. On March 6, 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines near Corpus Christi, Texas and contracts related to these pipelines from Onyx Midstream, LP and Onyx Pipeline Company (collectively, “Onyx”) for $38.6 million in cash, net of certain adjustments as provided in the purchase agreement.

The pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts that extend through 2029 and include an option to extend the agreements by an additional term of up to ten years. The contracts were renegotiated in connection with the acquisition; therefore, we considered these contracts to be assumed at fair market value.

The fair values of the property, plant and equipment were based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets. The fair value measurements and models were classified as non-recurring Level 3 measurements.
We performed our assessment of the fair value of the assets acquired and liabilities assumed, and the consideration given was considered equal to the fair value of net assets acquired. As a result, no goodwill was recorded. The assessment was finalized during the second quarter of 2014 and there were no subsequent changes to the preliminary balances recorded.
The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands):
Purchase Price—Cash
$
38,636

Current assets
$
730

Property, plant and equipment
39,413

Total assets acquired
40,143

Current liabilities assumed
(1,407
)
Other liabilities assumed
(100
)
Net identifiable assets acquired
$
38,636


14


Unaudited Pro Forma Financial Information for Onyx Pipelines Acquisition. The following unaudited pro forma financial information for the three months ended March 31, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except unit information):
 
Three Months Ended
 
March 31, 2014
Total revenue
$
214,240

Net loss
(1,397
)
Net loss attributable to common unitholders
(1,115
)
Net loss per common unit (basic and diluted)
(0.06
)
Net loss attributable to subordinated unitholders
(745
)
Net loss per subordinated unit (basic and diluted)
(0.06
)
The unaudited pro forma information is not necessarily indicative of what our statements of operations would have been if the transaction had occurred on that date, or what the financial position or results from operations will be for any future periods. For the period from March 6, 2014 through March 31, 2014, the Onyx pipelines business contributed $0.3 million in revenues and $0.1 million in net income to our statements of operations.
Texoz Acquisition. On November 21, 2014, we completed the acquisition of a natural gas gathering system in McMullen County, Texas (the “Texoz System”) from LT Gathering, LLC for $5.4 million in cash, net of certain adjustments as provided in the purchase agreement (the “Texoz Acquisition”). The Texoz System consists of eight miles of gathering pipelines within two miles of our existing rich gas pipeline network and services customers under acreage dedication contracts. Due to the immaterial amount of this transaction, no pro-forma financial information has been presented.

3. NET INCOME/LOSS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS
 
Net Income/Loss Per Limited Partner Unit
 
The following is a reconciliation of the net loss attributable to our limited partners and our limited partner units and the basic and diluted earnings per unit calculations for the three months ended March 31, 2015 and 2014 (in thousands, except unit and per unit data): 
 
 
Three Months Ended March 31,
 
 
2015
 
2014
Net loss
 
$
(10,751
)
 
$
(1,289
)
Series A Preferred Unit fair value adjustment (1)
 

 
33

Series A Preferred Unit in-kind distribution
 

 
(534
)
General partner Unit in-kind distribution
 
(76
)
 

    Net loss attributable to partners
 
$
(10,827
)
 
$
(1,790
)
 
 
 
 
 
General partner's interest (2)
 
(239
)
 
(26
)
Class B Convertible limited partner interest (2)
 
(3,119
)
 

Limited partners' interest (2)
 
 
 
 
    Common
 
(4,936
)
 
(1,045
)
    Subordinated
 
(2,533
)
 
(719
)

(1) The valuation adjustment to maximum redemption value of the Series A Preferred Unit in-kind distribution decreased the net loss attributable to partners for the three months ended March 31, 2014.

(2) General Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the allocation of Series A Preferred Unit in-kind distributions, Series A Preferred Unit fair value adjustments and General Partner unit in-kind distributions. The Class B Convertible Unit interest is calculated based on the allocation of only net losses for the period.

15


 
 
Three Months Ended March 31,
Common Units
 
2015
 
2014
Interest in net loss
 
$
(4,936
)
 
$
(1,045
)
Effect of dilutive units - numerator (1)
 

 

    Dilutive interest in net loss
 
$
(4,936
)
 
$
(1,045
)
 
 
 
 
 
Weighted-average units - basic
 
23,800,943

 
18,285,220

Effect of dilutive units - denominator (1)
 

 

    Weighted-average units - dilutive
 
23,800,943

 
18,285,220

 
 
 
 
 
Basic and diluted net loss per common unit
 
$
(0.21
)
 
$
(0.06
)

 
 
Three Months Ended March 31,
Subordinated Units
 
2015
 
2014
Interest in net loss
 
$
(2,533
)
 
$
(719
)
Effect of dilutive units - numerator(1)
 

 

    Dilutive interest in net loss
 
$
(2,533
)
 
$
(719
)
 
 
 
 
 
Weighted-average units - basic
 
12,213,713

 
12,213,713

Effect of dilutive units - denominator(1)
 

 

    Weighted-average units - dilutive
 
12,213,713

 
12,213,713

 
 
 
 
 
Basic and diluted net loss per subordinated unit
 
$
(0.21
)
 
$
(0.06
)

(1) Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts were 2,081 and 140,100 for the three months ended March 31, 2015 and 2014, respectively.
 
Our calculation of the number of weighted-average units outstanding includes the common units that have been awarded to our directors that are deferred under our Non-Employee Director Deferred Compensation Plan.

All of our Series A Preferred Units were converted into common units on August 4, 2014 (see Note 8). Prior to conversion, our Series A Preferred Units were considered participating securities for purposes of the basic earnings per unit calculation during periods in which they received cash distributions. We were required to pay in-kind distributions to the Series A Preferred Units for the first four full quarters beginning the second quarter of 2013, and continued to pay these distributions until the Series A Preferred Units were converted into common units. Because the Series A Preferred Units received in-kind distributions, they have been excluded from the basic earnings per unit calculation for the three months ended March 31, 2014.
 
Distributions
 
Our agreement of limited partnership, which was amended and restated on August 4, 2014 in order to establish the Class B Convertible Units (as amended and restated, the “Partnership Agreement”), requires that within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our General Partner. We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our General Partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Beginning with the third quarter of 2014, until such time that we have a distributable cash flow divided by cash distributions ratio (“Distributable Cash Flow Ratio”) of at least 1.0, Holdings, the holder of all of our subordinated units, waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0.


16


With respect to the fourth quarter of 2014, Holdings also waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution was paid before or in conjunction with the filing of our 2014 Annual Report on Form 10-K. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K.

 
Paid In-Kind Distributions
 
Series A Preferred Units. During the second quarter of 2013, we raised $40.0 million of equity through issuances of 1,715,000 Series A Preferred Units and an additional General Partner contribution to satisfy the requirements of our Previous Credit Facility (as defined in Note 6) (see Notes 6 and 8). Under the terms of our Partnership Agreement, we were required to pay the holders of our Series A Preferred Units quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issuance of the units and continuing thereafter until the board of directors of our General Partner determined to begin paying quarterly distributions in cash. In-kind distributions were in the form of Series A Preferred Units at a rate of $0.40 per outstanding Series A Preferred Unit per quarter (or 7% per year of the per unit purchase price). Cash distributions were required to equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit. In accordance with the Partnership Agreement, our General Partner received a corresponding distribution of in-kind general partner units to maintain its 2.0% interest in us. In connection with the Holdings Transaction (see Notes 1 and 2), all holders of the Series A Preferred Units elected to convert their Series A Preferred Units into 2,015,638 common units based on a 110% exchange ratio.

The following table represents the paid in-kind (“PIK”) distribution declared in 2014 through August 4, 2014, the date on which all outstanding Series A Preferred Units were converted to common units (in thousands, except per unit and in-kind distribution units): 
Payment Date
 
Attributable to the Quarter Ended(1)
 
Per Unit Distribution
 
In-Kind Series A
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


(1) As a result of the conversion, the Series A Preferred Unit holders (and the corresponding General Partner units) ceased receiving PIK distributions effective with the quarter ended June 30, 2014, but received a cash distribution on the converted common units.
(2) The fair value was calculated as required, based on the common unit price at the quarter end date for the period attributable to the distribution, multiplied by the number of units distributed.

Class B Convertible Units. In connection with the Contribution and the TexStar Rich Gas System Transaction, on August 4, 2014, we established our Class B Convertible Units. As of March 31, 2015, the Class B Convertible Units consist of 15,149,636 of such units including the additional Class B Convertible Units issued in-kind as a distribution (“Class B PIK Units”). The Class B Convertible Units are not participating securities for purposes of the earnings per unit calculation. Commencing with the quarter ended September 30, 2014 and until converted, as long as certain requirements are met, the holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit. These distributions will be paid quarterly in Class B PIK Units within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of 14,633,000 Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions. See Note 9.









17


The following table presents the PIK distribution earned on the Class B Convertible Units for periods after issuance on August 4, 2014 through March 31, 2015 (in thousands, except per unit and in-kind distribution units):
Payment Date
 
Attributable to the Quarter Ended
 
Per Unit Distribution
 
In-Kind Class B Convertible Unit
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)
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
May 14, 2015
 
March 31, 2015
 
$
0.3257

 
 
265,118

 
$
3,712

 
5,410

 
$
76

2014
 
 
 
 
 
 
 
 
 
 
 
 
 
February 13, 2015
 
December 31, 2014
 
$
0.3257

 
 
260,558

 
$
4,143

 
5,318

 
$
85

November 14, 2014
 
September 30, 2014
 
$
0.3257

 
 
256,078

 
$
5,467

 
5,226

 
$
112

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

Cash Distributions
 
The following table represents our distributions declared for the quarterly periods beginning in 2014 through the three months ended March 31, 2015 (in thousands, except per unit data): 
 
 
 
 
 
 
Distributions
 
 
 
 
Attributable to the
 
Per Unit
 
Limited Partners
 
 
 
 
Payment Date
 
Quarter Ended
 
Distribution
 
Common
 
Subordinated
 
General Partner
 
Total
2015
 
 
 
 
 
 
 
 
 
 
 
 
May 14, 2015
 
March 31, 2015
 
$
0.40

 
$
9,520

 
$

 
$
418

 
$
9,938

2014
 
 
 
 
 
 
 
 
 
 
 
 
February 13, 2015
 
December 31, 2014
 
0.40

(1) 
9,520

 
3,432

(2) 
416

 
13,368

November 14, 2014
 
September 30, 2014
 
0.40

(1) 
9,520

 

 
413

 
9,933

August 14, 2014
 
June 30, 2014
 
0.40

 
9,399

 
4,886

 
290

 
14,575

May 15, 2014
 
March 31, 2014
 
0.40

 
8,586

 
4,886

 
290

 
13,762


(1) The common unit distribution in the table above includes the distribution payment to the Series A Preferred unitholders for their Series A Preferred Units converted into common units or to the units that vested as part of our LTIP (as defined in Note 11) as a result of the Holdings Transaction (see Notes 1, 8 and 11).
(2) Holdings waived the requirement that any distribution owed to it for the fourth quarter be paid within 45 days of the end of the quarter. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K.

4. FINANCIAL INSTRUMENTS

Fair Value Measurements

We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:
Level 1—Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes our cash and cash equivalents, 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

18


category primarily includes variable rate debt, over-the-counter swap contracts based upon natural gas price indices and interest rate derivative transactions.
Level 3—Represents derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources. We do not have financial assets and liabilities classified as Level 3.

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

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

Derivative Financial Instruments
Interest Rate Derivative Transactions
We manage a portion of our interest rate risk through interest rate swaps. In March 2012, we terminated an interest rate cap contract and entered into an interest rate swap contract with Wells Fargo, N.A. The interest rate swap had a notional value of $150.0 million, and a maturity date of June 30, 2014. We received a floating rate based upon one-month London Interbank Offered Rate (“LIBOR”) and paid a fixed rate under the interest rate swap of 0.54%

The interest rate swap was designated as a cash flow hedge for accounting purposes at inception of the contract and, thus, to the extent the cash flow hedge was effective, unrealized gains and losses were recorded to accumulated other comprehensive income/loss and recognized in interest expense as the underlying hedged transactions (interest payments) were recorded. Any hedge ineffectiveness was recognized in interest expense immediately. We did not have any hedge ineffectiveness during the three months ended March 31, 2014.

In February 2014, we discontinued cash flow hedge accounting on a prospective basis as a result of the $148.5 million repayment of borrowings under our Previous Credit Facility (as defined in Note 6). The fair value of the interest rate swap recorded in accumulated other comprehensive loss at the cash flow hedge de-designation date was $0.1 million. This balance was reclassified into interest expense as interest on the hedged debt was recorded. No ineffectiveness was recorded as a result of the cash flow hedge de-designation. Changes in the fair value of the interest rate swap for the remainder of the contract term were recognized in interest expense.

We enter into interest rate swap contracts whereby we receive a floating rate and pay a fixed rate to reduce the risk associated with the variability of interest rates for our term loan borrowings. These interest rate swaps are not designated as cash flow hedges and as a result, changes in the fair value of the interest rate swaps are recognized in interest expense immediately.

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 March 31, 2015 or December 31, 2014. Our interest rate swap position was as follows (in thousands):
 
 
 
 
 
 
 
 
Estimated Fair Value
Notional Amount
 
Fixed Rate
 
Effective Date
 
Maturity Date
 
March 31, 2015
$
140,000

 
0.327
%
 
June 30, 2014
 
June 30, 2015
 
$
(51
)
50,000

 
1.198
%
 
September 30, 2014
 
June 30, 2016
 
(94
)
50,000

 
1.196
%
 
September 30, 2014
 
June 30, 2016
 
(94
)
 
 
 
 
 
 
 
 
$
(239
)

In December 2014, we entered into an interest rate cap contract for $20.0 million notional value, effective December 31, 2014, with a maturity date of December 31, 2016. The contract effectively caps our LIBOR-based interest rate on that portion of debt at 1.5%. We did not designate the interest rate cap as a hedging instrument for accounting purposes, and as a result, changes in the fair value are recognized in interest expense immediately.


19


The fair value of our interest rate derivative transactions is determined based on a discounted cash flow method using contractual terms of the transactions. The floating coupon rate is based on observable rates consistent with the frequency of the interest cash flows.

The fair values of our interest rate derivatives were as follows (in thousands):
 
Significant Other Observable Inputs (Level 2)
 
Fair Value Measurement as of
 
March 31, 2015
 
December 31, 2014
Current interest rate derivative assets
$
13

 
$
27

Non-current interest rate derivative assets
10

 
27

Current interest rate derivative (liabilities)
$
(202
)
 
$
(175
)
Non-current interest rate derivative (liabilities)
$
(37
)
 
$
(39
)
Total interest rate derivatives
$
(216
)
 
$
(160
)
 
The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and comprehensive loss was as follows (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Change in value recognized in other comprehensive loss - effective portion
$

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

 
115

 
There were no amounts of gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedge accounting due to the lack of probability of the forecasted transaction occurring.

The realized and unrealized amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Unrealized loss on interest rate derivatives
$
56

 
$
12

Realized loss on interest rate derivatives
104

 
27

 
Commodity Swaps
 
In our normal course of business, we periodically enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. We had no outstanding month-ahead swap contracts as of March 31, 2015. The total volume of outstanding month-ahead swap contracts as of December 31, 2014 was 12,000 MMBtu per day. We define these contracts as Level 2 because the index price associated with such contracts is observable and tied to a similarly quoted first-of-the-month natural gas index price.

We have elected to present our commodity swaps net on the balance sheets. We did not have any cash collateral received or paid on our commodity swaps as of March 31, 2015 or December 31, 2014. The effect of offsetting on our balance sheets was as follows (in thousands):
 
 
March 31, 2015
 
December 31, 2014
 
 
Other Current Assets
 
Other Current Liabilities
 
Other Current Assets
 
Other Current Liabilities
Gross amounts of recognized assets (liabilities)
 
$

 
$

 
$
112

 
$

Gross amounts offset on the balance sheets
 

 

 

 

Net amount
 
$

 
$

 
$
112

 
$


20


The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, was as follows (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Realized gain (loss) on commodity swap derivatives
$
125

 
$
(1,169
)
Unrealized gain (loss) on commodity swap derivatives
(111
)
 
44

5. LONG-LIVED ASSETS
Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
 
Estimated
Useful Life (yrs)
 
March 31, 2015
 
December 31, 2014
Pipelines
30
 
$
482,840

 
$
468,843

Gas processing, treating and other plants
15
 
491,780

 
482,418

Compressors
7
 
38,325

 
37,865

Rights of way and easements
15
 
29,810

 
29,803

Furniture, fixtures and equipment
5
 
3,735

 
3,671

Capital lease vehicles
3-5
 
2,284

 
2,077

    Total property, plant and equipment
 
 
1,048,774

 
1,024,676

Accumulated depreciation and amortization
 
 
(145,555
)
 
(131,615
)
    Total
 
 
903,219

 
893,061

Construction in progress
 
 
46,243

 
50,051

Land and other
 
 
22,153

 
25,698

    Property, plant and equipment, net
 
 
$
971,615

 
$
968,810

 
Depreciation is provided using the straight-line method based on the estimated useful life of each asset. 
 
In January 2015, we shut down our Gregory facility for four weeks due to a fire at the facility. In connection with the fire, as of March 31, 2015, the amount we had spent as part of efforts to return the facility to service did not exceed our insurance deductible. 
 
Intangible Assets

Intangible assets of $1.5 million as of March 31, 2015 and December 31, 2014, respectively, represent the unamortized value assigned to long-term supply and gathering contracts acquired in 2011. These intangible assets are amortized on a straight-line basis over the 30-year expected useful lives of the contracts through 2041. Amortization expense over the next five years related to intangible assets is not significant.


21


6. LONG-TERM DEBT 

Our outstanding debt and related information at March 31, 2015 and December 31, 2014 are as follows (in thousands):
 
March 31, 2015
 
December 31, 2014
Revolving credit facility due 2019
$
65,000

 
$
30,000

Term loans (including OID of $2.1 million) due 2021
444,592

 
445,629

Total long-term debt (including current portion)
509,592

 
475,629

Current portion of long-term debt
$
(4,500
)
 
$
(4,500
)
Total long-term debt
$
505,092

 
$
471,129

Outstanding letters of credit
$
20,830

 
$
30,130

Remaining unused borrowings
$
114,170

 
$
139,870

 
Three Months Ended March 31,
 
2015

2014
Weighted average interest rate
5.1
%
 
4.6
%
Average outstanding borrowings
$
512,093

 
$
192,403

Maximum borrowings
$
522,750

 
$
267,300


Previous Credit Facility
 
In November 2012, we entered into a five-year $350.0 million revolving credit facility (as amended, the “Previous Credit Facility”). Borrowings under the Previous Credit Facility were set to mature in November 2017. We utilized the Previous Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions and other general purposes. During 2013 and the first quarter of 2014, we entered into a total of four amendments to the Previous Credit Facility. In connection with these amendments, our availability was reduced from $350.0 million to the sum of $250.0 million plus any amounts placed on deposit in a collateral account of our General Partner and letters of credit outstanding. This availability was increased to $350.0 million in connection with the fourth amendment in March 2014. In connection with the closing of the TexStar Rich Gas System Transaction, we refinanced our Previous Credit Facility and entered into the Senior Credit Facilities (as defined below).

Senior Credit Facilities

On August 4, 2014, in connection with the consummation of the Contribution and TexStar Rich Gas System Transaction, we entered into (a) a Third Amended and Restated Revolving Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”) and (b) a Term Loan Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). The initial borrowings and extensions of credit under the Term Loan Agreement were used to finance the TexStar Rich Gas System Transaction (including the immediate repayment of the $100 million of debt assumed in the transaction), the repayment of certain of our existing debt and the payment of fees and expenses in connection with the new debt arrangements and ongoing working capital and other general partnership purposes. No amounts were initially drawn on the Third A&R Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest of the facilities ranking pari passu.

Third A&R Revolving Credit Agreement

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

(a)
the letters of credit sublimit increased to $75 million;


22


(b)
we have the right to increase the total commitments under the Credit Facility by obtaining additional commitments from other lenders, as long as our senior secured leverage ratio is less than or equal to 4.50 to 1.00 before and after giving effect to such increase, subject to certain other conditions;

(c)
the definition of “Change of Control” is amended to permit the combination transaction with TexStar and to reflect the Sponsors’ control of the General Partner;

(d)
our maximum consolidated total leverage ratio (i) was set at 5.75 to 1.00 as of the last day of the fiscal quarter ending each of September 30, 2014 and December 31, 2014, (ii) is set at 5.50 to 1.00 as of the last day of the fiscal quarter ending March 31, 2015, (iii) 5.25 to 1.00 as of the last day of the fiscal quarter ending June 30, 2015 and (iv) 5.00 to 1.00 as of the last day of each fiscal quarter thereafter;

(e)
we had the right, exercisable on or before the date that our annual audited financial statements were due for the 2014 fiscal year, to comply with the consolidated total leverage ratio, consolidated senior secured leverage ratio and the consolidated interest coverage ratio covenants (the “Financial Covenants”) by applying certain specified quarterly base periods and annualization methods pertaining to the TexStar Rich Gas System;

(f)
if we fail to comply with the Financial Covenants (a “Financial Covenant Default”), we have the right (which cannot be exercised more than two times in any 12-month period or more than four times during the term of the facility) to cure such Financial Covenant Default by having the Sponsors purchase equity interests in or make capital contributions to us resulting in, among other things, proceeds that, if added to consolidated EBITDA, as defined in the Third A&R Revolving Credit Agreement, would result in us satisfying the Financial Covenants;

(g)
certain definitions are amended to take into account the TexStar Rich Gas System; and

(h)
the negative covenants are amended to permit the entry into, and indebtedness under, the Term Loan Agreement.

On May 7, 2015, we entered into a first amendment to our Third A&R Revolving Credit Agreement that provides for more favorable financial covenants through the third quarter of 2016 and an equity cure that is available through then end of 2016. See Note 15.

Term Loan Agreement

The Term Loan Agreement is a seven-year $450 million senior secured term loan facility. On August 4, 2014, the lenders funded the full amount of the facility. Borrowings under our Term Loan Agreement bear interest at LIBOR plus 4.25% or a base rate as defined in the respective credit agreement with a LIBOR floor of 1.00%. Under the Term Loan Agreement, among other things:

(a)
subject to certain requirements, including the absence of a default and pro forma compliance under the Third A&R Revolving Credit Agreement and pro forma compliance with a senior secured leverage ratio less than or equal to 4.50 to 1.00 before and after giving effect to such increase, we may from time to time request incremental term loan commitments subject to certain other conditions;

(b)
we may seek commitments from third party lenders in connection with any incremental term loan commitment requests, subject to certain consent rights given to the administrative agent;

(c)
the guarantors and the collateral are the same as provided for the benefits of the lenders in the Third A&R Revolving Credit Agreement;

(d)
subject to certain conditions, we may request that the lenders extend the seven-year maturity of all or a portion of the outstanding loans under the facility;

(e)
the facility will amortize in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of the initial loan ($1.125 million), with the remainder due on the maturity date;

(f)
there are customary mandatory prepayment provisions and, subject to certain conditions, permissive prepayment provisions; provided, that if certain repricing transactions occur, we must pay a call premium equal to 1% of the principal amount of the loans subject to the repricing transactions; and


23


(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).

7. COMMITMENTS AND CONTINGENCIES
 
Legal Matters
 
On March 5, 2013, one of our subsidiaries, Southcross Marketing Company Ltd., filed suit in a District Court of Dallas County against Formosa Hydrocarbons Company, Inc. (“Formosa”).  The lawsuit sought recoveries of losses that we believe our subsidiary experienced as a result of the failure of Formosa to perform certain obligations under the gas processing and sales contract between the parties.  Formosa filed a response generally denying our claims and, later, Formosa filed a counterclaim against our subsidiary claiming our subsidiary breached the gas processing and sales contract and a related agreement between the parties for the supply by Formosa of residue gas to a third party on behalf of our subsidiary.  After a bench trial held in January 2015, on February 5, 2015, the judge ruled that Formosa breached certain of its obligations under the gas processing and sales contract and that our subsidiary breached an obligation under each of the gas processing and sales contract and the related residue gas agreement.  The amount of damages awarded to our subsidiary was in excess of the damages awarded to Formosa. Rather than wait for the judge to award attorneys’ fees for each party as to the claims on which it prevailed, the parties have reached an agreement as to the appropriate award of attorneys’ fees. The amount of attorneys’ fees to be paid to our subsidiary is in excess of the attorneys’ fees to be paid to Formosa. Our subsidiary has filed a motion for reconsideration regarding a claim that was dismissed before trial through summary judgment. Formosa has filed its own motion for reconsideration regarding the amount of damages awarded to our subsidiary on one of its claims. Even if Formosa is successful in its request to reduce the damages awarded to our subsidiary, the amount of damages awarded to our subsidiary would still be in excess of the damages awarded to Formosa. A hearing has been scheduled for June 5, 2015 on both parties’ motions. No judgment will be entered until the judge has made a ruling on these motions. Regardless of how the judge rules on these motions, the judgment is not expected to have a material impact on our results of operations, cash flows or financial condition. With the filing of this motion, we now expect a final judgment to be entered in the third quarter of 2015, which may be extended or appealed.
 
From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. For example, during periods when we are expanding our operations through the development of new pipelines or the construction of new plants, we may become involved in disputes with landowners that are in close proximity to our activities. While we are currently involved in several such proceedings and disputes, our management believes that none of such proceedings or disputes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims ultimately will have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.
 
Regulatory Compliance
 
In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition.
 
Leases

Capital Leases
 
We have auto leases that are classified as capital leases. The termination dates of the lease agreements vary from 2015 to 2019. We recorded amortization expense related to the capital leases of $0.1 million for each of the three months ended March 31, 2015 and 2014. Capital leases entered into during the three months ended March 31, 2015 and 2014 were $0.2 million and $0.3 million, respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands):
 
March 31, 2015
 
December 31, 2014
Other current liabilities
$
451

 
$
455

Other non-current liabilities
649

 
578

Total
$
1,100

 
$
1,033



24


Operating Leases
 
We maintain operating leases in the ordinary course of our business activities. These leases include those for office and other operating facilities and equipment. The termination dates of the lease agreements vary from 2015 to 2025. Expenses associated with operating leases, which are recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $1.2 million and $0.3 million for the three months ended March 31, 2015 and 2014, respectively.

Purchase Commitments
 
At March 31, 2015, we had commitments of approximately $18.3 million for purchases of material and equipment related to our capital projects, primarily related to the purchase of pipelines and compressors for our various capital expansion projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
 
8. SERIES A PREFERRED UNITS
 
During the second quarter of 2013, we entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the “Private Placement”). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013.

All of the Series A Preferred Units, including units held by Southcross Energy LLC, were converted to common units on August 4, 2014 in connection with the Holdings Transaction. See Notes 1 and 9.
 
9. PARTNERS’ CAPITAL
 
Ownership

Our units outstanding as of March 31, 2015 are as follows (in units):
 
 
 
 
Owned by Parent
 
 
Partners’ Capital
 
 
Public
 
 
 
Class B
 
 
 
General
 
 
Common
 
Common
 
Convertible
 
Subordinated
 
Partner
Units outstanding as of December 31, 2014
 
21,684,543

 
2,116,400

 
14,889,078

 
12,213,713

 
1,038,852

In-kind distributions and general partner issuances to maintain 2.0% ownership
 

 

 
260,558

 

 
5,318

Units outstanding as of March 31, 2015
 
21,684,543

 
2,116,400

 
15,149,636

 
12,213,713

 
1,044,170


Common Units
Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement.     
In February 2014, we completed a public equity offering of 9,200,000 additional common units and we received a capital contribution from our General Partner to maintain its 2.0% interest in us. The proceeds from the public offering were $144.7 million before estimated expenses related to the offering of $0.4 million. The net proceeds from the offering were used for our Onyx acquisition in March 2014, to fund the construction of our pipeline system extending into Webb County, Texas and for general partnership purposes.
In connection with the TexStar Rich Gas System Transaction and the Holdings Transaction on August 4, 2014, we issued Class B Convertible Units, accelerated the vesting of awards under our LTIP (see Note 11), and all of the holders of our Series A Preferred Units elected to convert their Series A Preferred Units into common units based on an exchange ratio of 110%.

25


Class B Convertible Units

In connection with the TexStar Rich Gas System Transaction, on August 4, 2014, we established our Class B Convertible Units. The Class B Convertible Units consist of 14,633,000 of such units plus any additional Class B PIK Units. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions as noted below.

Our Partnership Agreement does not allow additional Class B Convertible Units (other than Class B PIK Units) to be issued without the prior approval of our General Partner and the holders of a majority of the outstanding Class B Convertible Units.

Our Partnership Agreement provides that we will procure the listing of the common units issuable upon conversion of the Class B Convertible Units on the New York Stock Exchange or other applicable national securities exchange.

Distribution Rights: Commencing with the third quarter of 2014 and until converted, as long as certain requirements are met, the holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit. These distributions will be paid quarterly in Class B PIK Units within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us.

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

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

Changes in Partners’ Capital due to Holdings Transaction

As discussed in Note 1, on August 4, 2014, Southcross Energy LLC and TexStar combined. As a result of this transaction, Holdings, through a wholly-owned subsidiary, (a) acquired 100% of TexStar and its general partner from BBTS Borrower LP and (b) acquired 2,116,400 of our common units and 12,213,713 of our subordinated units from Southcross Energy LLC. Thus, as a result of that transaction, Holdings acquired an approximate 57.4% limited partner interest in us, as well as 100% of our General Partner, which owns an approximate 2.0% interest in us and our incentive distribution rights. BBTS Borrower LP is controlled by EIG and Tailwater. In December 2014, BBTS Borrower LP distributed to each of EIG and Tailwater, in relatively equal proportions, its interest in Holdings. Southcross Energy LLC is controlled by Charlesbank. The Holdings Transaction resulted in our Sponsors each indirectly owning approximately one-third of Holdings. Affiliates of Energy Capital Partners
Mezzanine Opportunities Fund and GE Energy Financial Services also own certain additional equity interests in Holdings.

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

With respect to the fourth quarter of 2014, Holdings also waived the requirement that any distribution owed to it for that quarter be paid within 45 days of the end of the quarter, provided that the distribution was paid before or in conjunction with the filing of our 2014 Annual Report on Form 10-K. We paid a distribution of $0.28 per unit on our 12,213,713 subordinated units in conjunction with the filing of our 2014 Annual Report on Form 10-K.

26


General Partner Interests
 
As defined by the Partnership Agreement, general partner units are not considered to be units (common or subordinated), but are representative of our general partner’s 2.0% ownership interest in us. Our General Partner has received general partner
unit PIK distributions from our general partner units purchased in connection with the Private Placement (see Note 8) and the Class B Convertible Units. In connection with other equity issuances, including issuances related to the TexStar Rich Gas System Transaction and the Holdings Transaction, our General Partner has made capital contributions in exchange for an issuance of additional general partner units to maintain its 2.0% ownership interest in us. Also, the General Partner has received general partner unit PIK distributions from the general partner units purchased in connection with the Private Placement (see Note 8).
Equity Distribution Agreement
On November 12, 2014, we established a $75 million "at-the-market" equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as our sales agent. Sales of the Offered Units, if any, made under the Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of sale in block transactions, or as otherwise agreed upon by us and any Manager. The Offered Units have been registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Registration No. 333-192105 declared effective December 10, 2013 (the "Registration Statement"), including the prospectus contained therein, as supplemented by the prospectus supplement filed with the SEC on November 12, 2014. We intend to use the net proceeds from the sale of the Offered Units for general partnership purposes, including the repayment of debt, acquisitions and funding capital expenditures.
The Distribution Agreement contains customary representations, warranties and agreements by us, including our obligations to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan Agreement, and affiliates of the other sales agents may from time to time hold positions under the Term Loan Agreement. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering. 
10. TRANSACTIONS WITH RELATED PARTIES
 
Charlesbank, EIG & Tailwater (our Sponsors)
 
Effective August 4, 2014, in connection with the Contribution and as a result of the Holdings Transaction, the board of directors of our General Partner includes one director affiliated with Charlesbank, one director affiliated with EIG, one director affiliated with Tailwater and three outside directors. The seventh member of the board of directors of our General Partner and its chairman, David W. Biegler, was selected by a majority of the other directors. Mr. Biegler will serve as the chairman from August 2014 for two years or until his earlier death or resignation. Our non-employee directors are reimbursed for certain expenses incurred for their services to us. The director services fees and expenses are included in general and administrative expenses in our statements of operations. We incurred fees and expenses related to the services from our affiliated directors as follows (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Charlesbank
$
14

 
$

EIG
16

 

Tailwater
16

 

Total fees and expenses paid for director services to affiliated entities
$
46

 
$



27


Southcross Energy Partners GP, LLC (our General Partner)
 
Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. We incurred expenses related to these reimbursements as follows (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Reimbursements included in general and administrative expenses
$
3,134

 
$
3,475

Reimbursements included in operations and maintenance expenses
4,781

 
3,943

Total reimbursements to our General Partner and its affiliates
$
7,915

 
$
7,418


Compensation expense for services incurred by us on behalf of Southcross Energy LLC was billed to Southcross Energy LLC. For the three months ended March 31, 2015, compensation expense, which was not incurred on our behalf, of $0.1 million was billed to Southcross Energy LLC. No such amounts were incurred by us and billed to Southcross Energy LLC for the three months ended March 31, 2014.
Wells Fargo Bank, N.A.
Under our Senior Credit Facilities, Wells Fargo Bank, N.A. serves as the administrative agent (and served in that same capacity under our Previous Credit Facility). See Note 6. An affiliate of Wells Fargo Bank, N.A. is a member of our investor group. We entered into amendments to our Previous Credit Facility during 2013 and 2014. In addition, in connection with the TexStar Rich Gas System Transaction, during the third quarter of 2014, we entered into the Senior Credit Facilities, which include syndicates of financial institutions and other lenders. Affiliates of Wells Fargo Bank, N.A. have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business. During the three months ended March 31, 2015 and 2014, we incurred costs, excluding interest, to Wells Fargo Bank, N.A. and its affiliates of $0.4 million and $0.2 million, respectively.

Other Transactions with Affiliates

Under the Distribution Agreement, we made customary representations, warranties and agreements, including an
agreement to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates
have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course
of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In
particular, affiliates of each of the Managers are lenders under our Senior Credit Facilities, an affiliate of Wells Fargo Securities, LLC is a lender under our Senior Credit Facilities and affiliates of the other sales agents may from time to time hold positions under the Term Loan Agreement. If we use any net proceeds of this offering to repay borrowings under our Senior Credit Facilities, such affiliates of the Managers will receive proceeds of the offering.

In conjunction with the TexStar Rich Gas System Transaction, we entered into a gas gathering and processing agreement (the “G&P Agreement”) and an NGL sales agreement (the “NGL Agreement”) with an affiliate of Holdings. Under the terms of these agreements, we transport, process and sell rich natural gas for the affiliate in return for fees that are substantially equivalent to the fees that Holdings receives from its customers for such services, and we can sell natural gas liquids that we own to Holdings at prices that are substantially equivalent to prices that Holdings receives from third parties. The NGL Agreement also permits us to utilize Holdings’ fractionation services at market-based rates.

During the three months ended March 31, 2015, the Partnership recorded revenues from affiliates of $7.4 million in accordance with the G&P Agreement and the NGL Agreement. Accounts receivable due from affiliates of $8.9 million as of March 31, 2015 is comprised of primarily (a) $5.6 million due from TexStar, (b) $0.9 million due from Holdings relating to gathering and processing services in the period and (c) $1.3 million, $0.6 million and $0.1 million due from T2 Eagle Ford, T2 Cogen and T2 LaSalle (each as defined in Note 13), respectively, representing reimbursements for operating costs and equipment for this investment in the joint ventures. Accounts payable due to affiliates of $3.8 million as of March 31, 2015 is comprised of primarily (a) $1.4 million due to TexStar, and (b) $1.7 million, $0.5 million and $0.1 million due to T2 Cogen, T2 Eagle Ford and T2 LaSalle, respectively, representing operational obligations.
 

28


11. INCENTIVE COMPENSATION
Unit Based Compensation
Long-Term Incentive Plan
On November 7, 2012, and in connection with our initial public offering, we established the 2012 Long-Term Incentive Plan (“LTIP”), which provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the LTIP vest over a three-year period in equal annual installments or in the event of a change in control of our General Partner in either a common unit or an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by management at its discretion. These awards also include distribution equivalent rights that grant the holder the right to receive an amount equal to the cash distributions on common units during the period the award remains outstanding.
 
The following table summarizes information regarding awards of units granted under the LTIP: 
 
Units
 
Weighted-Average Fair
Value at Grant Date
Unvested - December 31, 2014
470,750

 
$
20.45

  Granted units
372,283

 
$
13.80

  Forfeited units
(17,514
)
 
$
20.69

Unvested - March 31, 2015
825,519

 
$
18.15


For the three months ended March 31, 2015 and 2014, we granted awards under the LTIP with a grant date fair value of $5.1 million and $36 thousand, respectively, which we have classified as equity awards. As of March 31, 2015 and March 31, 2014, we had total unamortized compensation expense of $12.9 million and $3.2 million, respectively, related to unvested awards. Compensation expense associated with awards granted in the three months ended March 31, 2015 of 84,423 are expected to be recognized over a one-year vesting period, while the remaining awards are expected to be recognized over the three-year vesting period from each equity award’s grant date. As of March 31, 2015 and March 31, 2014, we had 545,515 and 1,525,121 units, respectively, available for issuance under the LTIP.

A grant of 84,423 units was made to the officers of our General Partner on March 10, 2015 that have a one-year vesting period rather than a three-year vesting period. These executive awards granted in March 2015 were not compensation earned for performance in 2014.
 
Unit Based Compensation Expense

The following table summarizes information regarding recognized compensation expense, which is included in general and administrative and operations and maintenance expense on our statements of operations (in thousands): 
 
Three Months Ended March 31,
 
2015
2014
Unit-based compensation
$
813

$
529

Employee Savings Plan
We have employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code of 1986, as amended, whereby employees of our General Partner may contribute a portion of their base compensation to the employee savings plan, subject to limits. We provide a matching contribution each payroll period equal to 100% of each employee’s contribution up to the lesser of 6% of the employee’s eligible compensation or $17,500 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in general and administrative expense on our statements of operations (in thousands): 
 
Three Months Ended March 31,
 
2015
 
2014
Matching contributions expensed for employee savings plan
$
181

 
$
356


29


2014 Incentive Plan
On August 4, 2014, our General Partner and Southcross GP Management Holdings, LLC, a Delaware limited liability company of which Holdings is the sole managing member (“GP Management”), adopted the Southcross Energy Partners GP, LLC and Southcross GP Management Holdings, LLC 2014 Equity Incentive Plan (the “2014 Incentive Plan”). Under the 2014 Incentive Plan, employees, consultants and directors of our General Partner and GP Management will be eligible to receive incentive compensation awards.
The 2014 Incentive Plan generally provides for the grant of awards, from time to time at the discretion of the board of directors of our General Partner (and, as applicable, the board of directors of the general partner of Holdings), of non-voting units in our General Partner to GP Management and then a corresponding grant or award of non-voting units of GP Management to the employee, consultant or director.
In connection with the adoption of the 2014 Incentive Plan, our General Partner amended and restated its limited liability company agreement and entered into its Second Amended and Restated Limited Liability Company Agreement which establishes a new class of non-voting units for issuance pursuant to the 2014 Incentive Plan and designates Southcross Holdings Borrower LP, a wholly owned subsidiary of Holdings as our General Partner’s managing member. As of March 31, 2015, no awards had been granted under this plan.
12. REVENUES
 
We had revenues consisting of the following categories (in thousands): 
 
Three Months Ended March 31,
 
2015

2014
Sales of natural gas
$
112,786

 
$
145,358

Sales of NGLs and condensate
37,183

 
51,874

Transportation, gathering and processing fees
29,663

 
16,115

Other
917

 
244

Total revenues
$
180,549

 
$
213,591

 
13. INVESTMENTS IN JOINT VENTURES

Assets acquired through the TexStar Rich Gas System Transaction include equity interests in three joint ventures. During 2012, a subsidiary of TexStar and a company subsequently acquired by Atlas Pipeline Partners, L.P. (“Atlas”) formed T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”, and collectively “T2 Rich Gas System”) to construct and operate a pipeline and cogeneration facility located in South Texas. During 2015, Atlas was acquired by Targa Pipeline Partners LP, which is now our joint venture partner. The Partnership indirectly has a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. The joint ventures’ summarized financial data from their statements of operations for the three months ended March 31, 2015 is as follows (in thousands):

 
Three Months Ended March 31, 2015
 
T2 Eagle Ford
 
T2 Cogen
 
T2 LaSalle
Revenue
$
921

 
$
1,662

 
$
379

Net loss
(4,997
)
 
(1,361
)
 
(1,520
)


30


The Partnership’s equity in losses of joint venture investments is comprised of the following for the three months ended March 31, 2015 (in thousands):
 
Three Months Ended
 
March 31, 2015
T2 Eagle Ford
$
(2,491
)
T2 Cogen
(681
)
T2 LaSalle
(380
)
Equity in losses of joint venture investments
$
(3,552
)
The Partnership’s investments in joint ventures is comprised of the following as of March 31, 2015 (in thousands):
 
March 31, 2015
T2 Eagle Ford
$
107,237

T2 Cogen
19,444

T2 LaSalle
18,994

Investments in joint ventures
$
145,675


14. CONCENTRATION OF CREDIT RISK
 
Our primary markets are in South Texas, Alabama and Mississippi. We have a concentration of revenues and trade accounts receivable due from customers engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect overall credit risk in that these customers may be affected similarly by changes in economic, regulatory or other factors. We analyze our customers’ historical financial and operational information before extending credit.
 
Our top ten customers for the three months ended March 31, 2015 and 2014 represent the following percentages of consolidated revenue: 
 
Three Months Ended March 31,
 
2015
 
2014
Top ten customers
71.0
%
 
64.6
%
 
The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three months ended March 31, 2015 and 2014 was as follows: 
 
Three Months Ended March 31,
 
2015
 
2014
Trafigura Trading LLC
12.8
%
 
12.2
%
Dow Hydrocarbons & Resources LLC
10.7
%
 
(a)

 
(a) Information is not provided for periods for which the customer or producer was less than 10% of our consolidated revenue.
 
For the three months ended March 31, 2015 and 2014, we did not experience significant non-payment for services. At March 31, 2015 and December 31, 2014, we did not record an allowance for uncollectible accounts receivable.
 

31


15. SUBSEQUENT EVENTS

Partnership Distributions

On April 28, 2015, the board of directors of our General Partner declared a cash distribution of $0.40 per common unit and General Partner unit, which will be paid on May 14, 2015 to unitholders of record on May 8, 2015. In addition, on April 28, 2015, the board of directors of our General Partner declared a $0.3257 per unit distribution for the first quarter of 2015 on the Partnership’s Class B Convertible Units. The distribution on the Class B Convertible Units will be paid in the form of additional Class B Convertible Units on May 14, 2015. In order to support the Partnership's acquisition of the TexStar Rich Gas System in August 2014, Holdings has elected to forgo distributions on any subordinated units that would cause the Partnership's distributions to exceed its distributable cash flow for any quarterly period. This election will continue
until the Partnership has distributable cash flow in excess of total distributions on the Partnership's common and subordinated
units and complies with the new restrictions in the Credit Agreement Amendment (defined below).

Holdings Drop-Down Transaction

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

The Valley Wells gathering system is located in the Eagle Ford Shale region, in LaSalle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d. The system is connected to our rich gas system for transport and processing. The Holdings Acquisition includes over 50,000 horsepower of compression assets that serve both the Valley Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines include a Y-grade pipeline that when completed will connect our Woodsboro processing facility to Holdings’ Robstown fractionator (“Robstown”) and a propane pipeline that when completed will be from our Bonnie View fractionator to Robstown. The NGL lines are expected to be in operation by the third quarter of 2015.

Amendment to Third A&R Revolving Credit Agreement

During the fourth quarter of 2014 and into the first quarter of 2015, as a result of the decline in commodity prices and associated decline in upstream drilling activity, we experienced a decline in the growth in volume of natural gas we gather and process for our customers. Our results in the first quarter of 2015 were also negatively impacted by the fire at our Gregory facility. These collective events impacted our operating results adversely and resulted in the need to amend our Credit Facility.

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

The Credit Agreement Amendment, among other things, (a) revised the maximum consolidated total leverage ratio set at 5.75 to 1.0 as of the last day of the fiscal quarter ending each of March 31, 2015, June 30, 2015 and September 30, 2015, (ii) 5.5 to 1.0 as of the last day of the fiscal quarter ending each of December 31, 2015, March 31, 2016 and June 30, 2016, (iii) 5.25 to 1.0 as of the last day of the fiscal quarter ending September 30, 2016, and (iv) 5.00 to 1.0 as of the last day of each fiscal quarter thereafter, in each case, without any step-ups in connection with acquisitions; (b) increased the applicable margins used in connection with the loans and the commitment fee so that the applicable margin for Eurodollar Loans ranges from 2.00% to 4.50%, the applicable margin for Base Rate Loans ranges from 1.00% to 3.50% and the applicable rate for commitment fees ranges from 0.375% to 0.500%, (c) permits the Partnership to comply with certain Financial Covenants by making certain pro forma adjustments with respect to minimum revenues to be received from Frio, (d) modified our ability to cure Financial Covenant defaults; (e) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units; and (f) amended certain other provisions of the Third A&R Revolving Credit Agreement as more specifically set forth in the Credit Agreement Amendment.


32


16. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)
 
Three Months Ended March 31,
 
2015
 
2014
Supplemental Disclosures:
 
 
 
Cash paid for interest, net of amounts capitalized
$
6,841

 
$
2,776

Cash paid for taxes, net of refunds received

 
23

Supplemental disclosures of non-cash investing and financing activities:


 


Accounts payable related to capital expenditures
11,899

 
1,628

Change in value recognized in other comprehensive loss

 
11

Capital lease obligations
207

 
307

Accrued distribution equivalent rights on LTIP units
334

 
76

Class B Convertible unit in-kind distributions
3,712

 

Capitalization of Interest Cost
We capitalize interest on projects during their construction period. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is depreciated over the estimated useful life of the asset constructed. We incurred the following interest costs (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Total interest costs
$
7,800

 
$
3,072

Capitalized interest included in property, plant and equipment, net
(302
)
 
(99
)
Interest expense
$
7,498

 
$
2,973

Deferred Financing Costs

Deferred financing costs are capitalized and amortized as interest expense under the effective interest method over the term of the related debt. The unamortized balance of deferred financing costs is included in other assets on the balance sheets. Changes in deferred financing costs are as follows (in thousands):
 
2015
 
2014
Deferred financing costs, January 1
$
16,602

 
$
5,237

Capitalization of deferred financing costs (1)
6

 
156

Amortization of deferred financing costs
(737
)
 
(337
)
Deferred financing costs, March 31
$
15,871

 
$
5,056

 
(1) See Note 6.

Southcross Assets Considered Leases to Third Parties

In connection with the Onyx acquisition in March 2014, we acquired natural gas pipelines and contracts related to the acquired pipelines (see Note 2). The pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts. The contracts have a primary term through 2029 and an option to extend the agreements by an additional term of up to ten years. These contracts are considered operating leases under the applicable accounting guidance.
  
Future minimum annual demand payment receipts under these agreements as of March 31, 2015 were as follows: $4.2 million for the remainder of 2015; $5.6 million in 2016; $5.6 million in 2017; $2.2 million in 2018; $2.2 million in 2019; and $15.3 million thereafter. The revenue for the demand payments is recognized on a straight-line basis over the term of the contract. The demand fee revenues under the contracts were $0.7 million and $0.2 million for the three months ended March 31, 2015 and 2014, respectively, and have been included within transportation, gathering and processing fees within Note 12. These amounts do not include variable fees based on the actual gas volumes delivered under the contracts. Variable fees

33


recognized in revenues within transportation, gathering and processing fees within Note 12 were $0.8 million and $1.2 million for the three months ended March 31, 2015 and 2014, respectively.


34


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, a Delaware limited liability company, held all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”), all of our subordinated units and a portion of our common units. Southcross Energy LLC is controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”).

Holdings Transaction

On August 4, 2014, Southcross Energy LLC and TexStar Midstream Services, LP, a Texas limited partnership (“TexStar”), combined pursuant to a contribution agreement in which Southcross Holdings LP, a Delaware limited partnership (“Holdings”), was formed (the “Holdings Transaction”). As a result of the Holdings Transaction, Holdings indirectly owns 100% of our General Partner (and therefore controls us), all of our subordinated units and a portion of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights. Charlesbank, EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services also own certain additional equity interests in Holdings.

TexStar Rich Gas System Transaction

Contemporaneously with the closing of the Holdings Transaction, TexStar contributed to us certain gathering and processing assets (the “TexStar Rich Gas System”), which were owned by TexStar (the “TexStar Rich Gas System Transaction”). For additional details regarding the Holdings Transaction and the TexStar Rich Gas System Transaction, see Notes 1, 2, 6, 9, 10 and 13 to our condensed consolidated financial statements.

Holdings Drop-Down Transaction

On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “Holdings Acquisition”) from Holdings and its subsidiaries pursuant to a Purchase, Sale and Contribution Agreement among Holdings, TexStar Midstream Utility, LP, Frio LaSalle Pipeline, LP (“Frio”), us and certain of our subsidiaries. The acquired assets consist of the Valley Wells sour gas gathering and treating system, compression assets that are part of the Valley Wells and Lancaster gathering and treating systems and two NGL pipelines that are currently under construction. Total consideration for the assets was $15.0 million in cash and 4.5 million new common units, valued as of the date of closing, issued to Holdings equating to $77.6 million. We assumed approximately $26.0 million in remaining capital expenditures for the completion of the NGL pipelines that are currently under construction.

The Valley Wells gathering system is located in the Eagle Ford Shale region, in LaSalle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 35 MMcf/d minimum volume commitment. The system is connected to our rich gas system for transport and processing. The Holdings Acquisition includes over 55,000 horsepower of compression assets that serve both the Valley Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines include a Y-grade pipeline that when completed will connect our Woodsboro processing facility to Holdings’ Robstown fractionator (“Robstown”) and a propane pipeline that when completed will be from our Bonnie View fractionator to Robstown. The NGL lines are expected to be in operation by the third quarter of 2015.

The Valley Wells system, the compression assets and the Y-grade pipeline have long-term fixed-fee minimum volume or minimum utilization agreements that represent over 80% of the anticipated annualized EBITDA. Upon completion, the propane pipeline will result in immediate savings for us over the current cost of transportation for deliveries of propane from our Bonnie View fractionator.


35


Liquidity Consideration
Beginning in the second half of 2014 and continuing through the issuance of our financial statements, commodity prices have experienced increased volatility. In particular, natural gas, crude oil and NGL prices have decreased significantly. If a material reduction in drilling occurs in the geographic areas in which we operate, including the Eagle Ford Shale region, or significant, prolonged pricing deterioration occurs for commodities we sell, our future cash flow may be materially adversely affected.
The majority of our revenue is derived from fixed-fee contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than the value of the underlying natural gas or NGLs, although a percentage of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity.
After considering these uncertainties and in developing our annual budget for 2015, our forecast indicates a potential shortfall in the amount of consolidated EBITDA (as defined in our Credit Facility (as defined below)) to comply with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 6 to our condensed consolidated financial statements) in our Credit Facility. As discussed in further detail in Note 6 to our condensed consolidated financial statements, we have the right (which cannot be exercised more than two times in any 12-month period or more than four times during the term of the facility) to cure such a Financial Covenant Default (as defined in Note 6 to our condensed consolidated financial statements) by our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we would also experience a cross default under our Term Loan Agreement (defined in Note 6 to our condensed consolidated financial statements) and all of our debt would become due and payable to our lenders.
In response to the Partnership’s expected need for additional liquidity, our Sponsors have committed to provide the necessary funding to support the Partnership for at least a reasonable period of time in an amount up to $25 million to ensure the Partnership has sufficient liquidity to comply with its applicable Financial Covenants, and to fund normal operating and growth capital requirements. Therefore, our financial statements have been presented as if the Partnership will continue as a going concern. See Notes 6 and 15 to our condensed consolidated financial statements.
Amendment to Third A&R Revolving Credit Agreement

During the fourth quarter of 2014 and into the first quarter of 2015, as a result of the decline in commodity prices and associated decline in upstream drilling activity, we experienced a decline in the growth in volume of natural gas we gather and process for our customers. Our results in the first quarter of 2015 were also negatively impacted by the fire at our Gregory facility. These collective events impacted our operating results adversely and resulted in the need to amend our Credit Facility.

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

The Credit Agreement Amendment, among other things, (a) revised the maximum consolidated total leverage ratio set at 5.75 to 1.0 as of the last day of the fiscal quarter ending each of March 31, 2015, June 30, 2015 and September 30, 2015, (ii) 5.5 to 1.0 as of the last day of the fiscal quarter ending each of December 31, 2015, March 31, 2016 and June 30, 2016, (iii) 5.25 to 1.0 as of the last day of the fiscal quarter ending September 30, 2016, and (iv) 5.00 to 1.0 as of the last day of each fiscal quarter thereafter, in each case, without any step-ups in connection with acquisitions; (b) increased the applicable margins used in connection with the loans and the commitment fee so that the applicable margin for Eurodollar Loans ranges from 2.00% to 4.50%, the applicable margin for Base Rate Loans ranges from 1.00% to 3.50% and the applicable rate for commitment fees ranges from 0.375% to 0.500%, (c) permits the Partnership to comply with certain Financial Covenants by making certain pro forma adjustments with respect to minimum revenues to be received from Frio, (d) modified our ability to cure Financial Covenant Defaults; (e) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units; and (f) amended certain other provisions of the Third A&R Revolving Credit Agreement as more specifically set forth in the Credit Agreement Amendment.
 

36


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.

Our Operations

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

37


The following table summarizes our gross operating margins from these arrangements (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
 
Gross Operating Margin
 
%
 
Gross Operating Margin
 
%
Fixed-fee
$
30,216

 
76.6
%
 
$
16,253

 
59.8
%
Fixed-spread
4,134

 
10.5
%
 
3,886

 
14.3
%
Sub-total
34,350

 
87.1
%
 
20,139

 
74.1
%
Commodity-sensitive
5,084

 
12.9
%
 
7,049

 
25.9
%
Total gross operating margin
$
39,434

 
100.0
%
 
$
27,188

 
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, 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;

38


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): 

Three Months Ended March 31,

2015
 
2014
Reconciliation of gross operating margin to net loss
 
 
 
Gross operating margin
$
39,434

 
$
27,188

(Deduct):
 
 
 
Income tax expense
(69
)
 
(8
)
Equity in losses of joint venture investments
(3,552
)
 

Interest expense
(7,498
)
 
(2,973
)
Loss on sale of assets, net
(218
)
 
(4
)
General and administrative
(7,705
)
 
(6,103
)
Depreciation and amortization
(13,953
)
 
(8,528
)
Operations and maintenance
(17,190
)
 
(10,861
)
Net loss
$
(10,751
)
 
$
(1,289
)






39


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 March 31,
 
2015
 
2014
Net cash provided by operating activities
$
3,428

 
$
14,176

Add (deduct):


 


Depreciation and amortization
(13,953
)
 
(8,528
)
Unit-based compensation
(813
)
 
(529
)
Amortization of deferred financing costs
(825
)
 
(337
)
Loss on sale of assets, net
(218
)
 
(4
)
Unrealized loss (gain) on financial instruments
(167
)
 
32

Equity in losses of joint venture investments
(3,552
)
 

Other, net
(18
)
 
(14
)
Changes in operating assets and liabilities:


 


Trade accounts receivable, including affiliates
(19,082
)
 
7,477

Prepaid expenses and other current assets
297

 
(813
)
Other non-current assets
(170
)
 
25

Accounts payable and accrued expenses
27,111

 
(13,694
)
Other liabilities, including affiliates
(2,789
)
 
920

Net loss
$
(10,751
)
 
$
(1,289
)
Add (deduct):