SXE - 10Q - 2014.3.31 - Q1
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, 2014
 
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from             to             
 
Commission File Number: 001-35719
 
Southcross Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
 
DELAWARE
 
45-5045230
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
1700 Pacific Avenue, Suite 2900
Dallas, TX
 
75201
(Address of principal executive offices)
 
(Zip Code)
 
(214) 979-3720
(Registrant’s telephone number, including area code)
 
 
(Former name, former address and former fiscal year, if changed since last report)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o
 
Accelerated filer x
 
 
 
Non-accelerated filer o
(Do not check if a smaller reporting company)
 
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
 
Indicate the number of units outstanding of the issuer’s classes of common units, subordinated units and Series A Convertible Preferred Units, as of the latest practicable date:
 
As of May 7, 2014, the registrant has 21,465,046 common units outstanding, 12,213,713 subordinated units outstanding and 1,800,886 Series A Convertible Preferred Units outstanding.  Our common units trade on the NYSE under the symbol “SXE.”

Table of Contents

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

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

2
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FORM 10-Q
TABLE OF CONTENTS
Southcross Energy Partners, L.P.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

3
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FORWARD-LOOKING INFORMATION
 
Investors are cautioned that certain statements contained in this Quarterly Report on Form 10-Q 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 herein and in our 2013 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 Quarterly Report on Form 10-Q and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by these risks and uncertainties. These risks and uncertainties include, among others:
 
•
the volatility of natural gas, crude oil and NGL prices and the price and demand of products derived from these commodities;
•
competitive conditions in our industry and the extent and success of producers increasing production or replacing declining production and our success in obtaining new sources of supply;
•
industry conditions and supply of pipelines, processing and fractionation capacity relative to available natural gas from producers;
•
our dependence upon a relatively limited number of customers for a significant portion of our revenues;
•
actions taken, inactions or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;
•
our ability to effectively recover NGLs at a rate equal to or greater than our contracted rates with customers;
•
our ability to produce and market NGLs at the anticipated differential to NGL index pricing;
•
our access to markets enabling us to match pricing indices for purchases and sales of natural gas and NGLs;
•
our ability to complete projects within budget and on schedule, including but not limited to, timely receipt of necessary government approvals and permits, our ability to control the costs of construction and other factors that may impact projects;
•
our ability to consummate acquisitions, successfully integrate the acquired businesses and realize anticipated cost savings and other synergies from any acquisitions;
•
our ability to manage over time changing exposure to commodity price risk;
•
the effectiveness of our hedging activities or our decisions not to undertake hedging activities;
•
our access to financing and ability to remain in compliance with our financing covenants;
•
our ability to generate sufficient operating cash flow to fund our quarterly distribution;
•
changes in general economic conditions;
•
the effects of downtime associated with our assets or the assets of third parties interconnected with our systems;
•
operating hazards, fires, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
•
the failure of our processing and fractionation plants to perform as expected, including outages for unscheduled maintenance or repair;
•
the effects of laws and governmental regulations and policies;
•
the effects of existing and future litigation; and
•
other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the U.S. Securities and Exchange Commission.
 
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected, affect our ability to maintain distribution levels and/or access necessary financial markets or cause a significant reduction in the market price of our common units.
 
The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this Quarterly Report on Form 10-Q 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.

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PART I — FINANCIAL INFORMATION
 
Item 1. Financial Statements.
 
SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit data)
(Unaudited)
 
 
March 31, 2014
 
December 31, 2013
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
4,434

 
$
3,349

Trade accounts receivable
65,876

 
57,669

Prepaid expenses
1,893

 
3,061

Other current assets
5,493

 
5,105

Total current assets
77,696

 
69,184


 
 
 
Property, plant and equipment, net
617,162

 
575,795

Intangible assets, net
1,554

 
1,568

Other assets
5,612

 
5,768

Total assets
$
702,024

 
$
652,315

 
 
 
 
LIABILITIES, PREFERRED UNITS AND PARTNERS' CAPITAL
 
 
 

Current liabilities:
 
 
 

Accounts payable and accrued liabilities
$
74,517

 
$
62,451

Other current liabilities
5,804

 
5,344

Total current liabilities
80,321

 
67,795


 
 
 
Long-term debt
170,850

 
267,300

Other non-current liabilities
2,081

 
1,692

Total liabilities
253,252

 
336,787


 
 
 
Commitments and contingencies (Note 7)


 


 
 
 
Series A convertible preferred units (1,800,886 and 1,769,915 units issued and outstanding as of March 31, 2014 and December 31, 2013, respectively)
41,005

 
40,504


 
 
 
Partners' capital:
 

 
 
Common units (23,163,713 and 13,963,713 units authorized; 21,454,119 and 12,253,985 units outstanding as of March 31, 2014 and December 31, 2013, respectively)
304,586

 
169,141

Subordinated units (12,213,713 units authorized and outstanding as of March 31, 2014 and December 31, 2013)
94,120

 
99,726

General Partner interest
9,167

 
6,367

Accumulated other comprehensive loss
(106
)
 
(210
)
Total partners' capital
407,767

 
275,024

Total liabilities, preferred units and partners' capital
$
702,024

 
$
652,315

 
See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for per unit data)
(Unaudited)
 
 
Three Months Ended March 31,
 
2014
 
2013
Revenues
$
213,591

 
$
144,250

Expenses:
 

 
 
Cost of natural gas and liquids sold
186,403

 
125,388

Operations and maintenance
10,861

 
9,889

Depreciation and amortization
8,528

 
7,249

General and administrative
6,103

 
6,041

Loss on asset disposal
4

 
—

Total expenses
211,899

 
148,567

 
 
 
 
Income (loss) from operations
1,692

 
(4,317
)
Interest expense
(2,973
)
 
(2,047
)
Loss before income tax expense
(1,281
)
 
(6,364
)
Income tax expense
(8
)
 
(18
)
Net loss
(1,289
)
 
(6,382
)
Series A convertible preferred unit in-kind distribution
(534
)
 
—

Series A preferred unit valuation adjustment to maximum redemption value
33

 
—

Net loss attributable to partners
(1,790
)
 
(6,382
)
 
 
 
 
General partner's interest in net loss
(26
)
 
(128
)
Limited partners' interest in net loss
$
(1,764
)
 
$
(6,254
)
 
 

 
 
Basic and diluted earnings per unit
 
 
 
Net loss allocated to limited partner common units
$
(1,045
)
 
$
(3,127
)
Weighted average number of limited partner common units outstanding
18,285,220

 
12,213,713

Loss per common unit
$
(0.06
)
 
$
(0.26
)
 
 
 
 
Net loss allocated to limited partner subordinated units
$
(719
)
 
$
(3,127
)
Weighted average number of limited partner subordinated units outstanding
12,213,713

 
12,213,713

Loss per subordinated unit
$
(0.06
)
 
$
(0.26
)
 
See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
(Unaudited)
 
 
Three Months Ended March 31,
 
2014
 
2013
Net loss
$
(1,289
)
 
$
(6,382
)
Other comprehensive income (loss):
 

 
 

Hedging losses reclassified to earnings and recognized in interest expense
115

 
94

Adjustment in fair value of derivatives
(11
)
 
(69
)
Total other comprehensive income (loss)
104

 
25

Comprehensive loss
$
(1,185
)
 
$
(6,357
)
 
See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
 
 
Three Months Ended March 31,
 
2014
 
2013
Cash flows from operating activities:
 
 
 
Net loss
$
(1,289
)
 
$
(6,382
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation and amortization
8,528

 
7,249

Unit-based compensation
529

 
408

Amortization of deferred financing costs
337

 
267

Loss on asset disposal
4

 
—

Unrealized gain on financial instruments
(32
)
 
—

Other, net
14

 
—

Changes in operating assets and liabilities:

 

Trade accounts receivable
(7,477
)
 
8,648

Prepaid expenses and other current assets
813

 
1,199

Other non-current assets
(25
)
 
(13
)
Accounts payable and accrued liabilities
13,694

 
(11,725
)
Other liabilities
(920
)
 
(1,362
)
Net cash provided by (used in) operating activities
14,176

 
(1,711
)
Cash flows from investing activities:
 
 
 
Capital expenditures
(11,087
)
 
(49,203
)
Expenditures for assets subject to property damage claims, net of insurance proceeds and deductibles
(693
)
 
(2,825
)
Assets acquired
(38,636
)
 
—

Net cash used in investing activities
(50,416
)
 
(52,028
)
Cash flows from financing activities:
 
 
 
Proceeds from issuance of common units, net
144,715

 
—

Borrowings under our credit agreements
62,000

 
55,000

Repayments under our credit agreements
(158,450
)
 
—

Payments on capital lease obligations
(143
)
 
—

Financing costs
(156
)
 
(519
)
Contributions from general partner
3,115

 
—

Payments of distributions and distribution equivalent rights
(13,755
)
 
(5,982
)
LTIP tax withholdings on vested units
(1
)
 
—

Net cash provided by financing activities
37,325

 
48,499

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

 
(5,240
)
Cash and cash equivalents — Beginning of period
3,349

 
7,490

Cash and cash equivalents — End of period
$
4,434

 
$
2,250

 
See accompanying notes.

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

 
Partners' Capital



 
Limited Partners



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
)
LTIP tax withholdings on 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


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

 
$
125,951

 
$
6,628

 
$
(477
)
 
$
326,467

Net loss
 
(3,127
)
 
(3,127
)
 
(128
)
 
—

 
(6,382
)
Unit-based compensation on long-term incentive plan
 
262

 
—

 
—

 
—

 
262

Cash distributions paid
 
(2,931
)
 
(2,931
)
 
(120
)
 
—

 
(5,982
)
Net effect of cash flow hedges
 
—

 
—

 
—

 
25

 
25

BALANCE - March 31, 2013
$
188,569

 
$
119,893

 
$
6,380

 
$
(452
)
 
$
314,390


See accompanying notes.

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SOUTHCROSS ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
 
1.              ORGANIZATION, 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.” Southcross Energy LLC is a Delaware limited liability company. Southcross Energy LLC holds all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”), all of our subordinated units, as well as a portion of our common units and Series A Convertible Preferred Units (“Series A Preferred Units”) originally issued during the second quarter of 2013. Southcross Energy LLC and its subsidiaries are controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC ("Charlesbank").
 
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 three gas processing plants, two fractionation plants and our pipelines. We are headquartered in Dallas, Texas and our operations are managed as and presented in one reportable segment.
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 make decisions about resource allocations and assess our performance. 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 Quarterly Report on Form 10-Q under the rules and regulations of the Securities and Exchange Commission and in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements. Accordingly, these condensed consolidated financial statements do not include all of the disclosures required by GAAP and should be read with our 2013 Annual Report on Form 10-K. The condensed consolidated financial statements as of March 31, 2014 and December 31, 2013, and for the three months ended March 31, 2014 and 2013, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2013 Annual Report on Form 10-K.  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 as of March 31, 2014 and the operating results for the period from March 6, 2014 through March 31, 2014 associated with the acquisition discussed further in Note 2. Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included herein.
 
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 consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from those estimates. Information for interim periods may not be indicative of our operating results for the entire year.
 
The disclosures included in this report provide an update to our 2013 Annual Report on Form 10-K.
 
We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure.  Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed in this report.
 
Significant Accounting Policies
 

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During the first quarter of 2014, there were no material changes to our significant accounting policies described in Note 1 of our 2013 Annual Report on Form 10-K.
 
Recent Accounting Pronouncements
 
Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review new pronouncements to determine their impact, if any, on our consolidated financial statements, and currently there are no new accounting pronouncements that would have a material impact.

2. ACQUISITION

On March 6, 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines near Corpus Christi, Texas and contracts related to these pipelines from Onyx Midstream, LP and Onyx Pipeline Company (collectively, “Onyx”) for $38.6 million in cash, net of certain adjustments as provided in the purchase agreement.

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

The preliminary fair values of the property, plant and equipment are based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. We utilized a mix of the cost, income and market approaches to determine the estimated fair values of such assets. The fair value measurements and models have been classified as non-recurring Level 3 measurements.
We are performing our preliminary assessment of the fair value of the assets acquired and liabilities assumed as of March 31, 2014 and we expect that the consideration given will be equal to the fair value of net assets acquired. As a result, no goodwill is expected to be recorded. We have not completed the final purchase price allocation of the assets acquired and liabilities assumed as of March 31, 2014 because we have not completed our determination of the valuation of the property, plant and equipment.
The reconciliation of the preliminary 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

In the first quarter of 2014, we expensed $0.3 million of transaction costs associated with the acquisition. These costs are reported within general and administrative expenses.
The following unaudited pro forma financial information of our periods ended March 31, 2014 and 2013 assumes that the Onyx acquisition occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the acquisition (in thousands, except unit information):
 
Three months ended March 31,
 
2014
 
2013
Total revenue
$
214,240

 
$
145,286

Net loss
(1,397
)
 
(7,238
)
Net loss attributable to common unitholders
(1,115
)
 
(3,876
)
Net loss per common unit—(basic and diluted)
(0.06
)
 
(0.26
)
Net loss attributable to subordinated unitholders
(745
)
 
(3,231
)
Net loss per subordinated unit—(basic and diluted)
(0.06
)
 
(0.26
)

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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, Onyx contributed $0.3 million in revenues and $0.1 million in net loss to our statements of operations.
3. NET (LOSS) INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS
 
Net (Loss) Income 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, 2014 and 2013 (in thousands, except unit and per unit data): 
 
 
Three Months Ended March 31, 2014
 
Three Months Ended March 31, 2013
Net loss
 
$
(1,289
)
 
$
(6,382
)
Series A Preferred Unit in-kind distribution and fair value adjustment (1)
 
(501
)
 
—

    Net loss attributable to partners
 
$
(1,790
)
 
$
(6,382
)
 
 
 
 
 
General partner's interest (2)
 
$
(26
)
 
$
(128
)
Limited partners' interest (2)
 
 
 
 
    Common
 
$
(1,045
)
 
$
(3,127
)
    Subordinated
 
$
(719
)
 
$
(3,127
)

(1) The Series A Preferred Unit in-kind distribution increased the net loss attributable to partners as of March 31, 2014 in the calculation of earnings per unit (See Note 9) for the three months ended March 31, 2014. The valuation adjustment to maximum redemption value of the Series A Preferred Units as of March 31, 2014 decreased the net loss available to common units in the calculation of earnings per unit (See Note 9) for the three months ended March 31, 2014. There is no in-kind distribution or valuation adjustment to maximum redemption value for the Series A Preferred Units as of March 31, 2013 in the calculation of earnings per unit (See Note 9) for the three months ended March 31, 2013.
 
(2) General Partner's and Limited Partners’ interest 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.

Common Units
 
Three Months Ended March 31, 2014
 
Three Months Ended March 31, 2013
Interest in net loss
 
$
(1,045
)
 
$
(3,127
)
Effect of dilutive units - numerator (1)
 
—

 
—

    Dilutive interest in net loss
 
$
(1,045
)
 
$
(3,127
)
 
 
 
 
 
Weighted-average units - basic
 
18,285,220

 
12,213,713

Effect of dilutive units - denominator (1)
 
—

 
—

    Weighted-average units - dilutive
 
18,285,220

 
12,213,713

 
 
 
 
 
Basic and diluted net loss per common unit
 
$
(0.06
)
 
$
(0.26
)


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Subordinated Units
 
Three Months Ended March 31, 2014
 
Three Months Ended March 31, 2013
Interest in net loss
 
$
(719
)
 
$
(3,127
)
Effect of dilutive units - numerator (1)
 
—

 
—

    Dilutive interest in net loss
 
$
(719
)
 
$
(3,127
)
 
 
 
 
 
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
 
$
(0.06
)
 
$
(0.26
)

(1) Because we had a net loss for the three months ended March 31, 2014 and 2013, 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. The weighted average units that would be included in the computation of diluted per unit amounts in accordance with the treasury stock method were 4,779 unvested awards granted under our long-term incentive plan (See Note 11) and 1,800,886 Series A Preferred Units (See Note 9) for the three months ended March 31, 2014. The amount of unvested common units that were not included in the computation of diluted per unit amounts were 140,100 unvested awards granted under our long-term incentive plan for the three months ended March 31, 2013. Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award should be included in the diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method.
 
Our calculation of the number of weighted-average units outstanding include the common units that have been awarded to our directors that are deferred under our Non-Employee Director Deferred Compensation Plan.

The Series A Preferred Units are considered participating securities for purposes of the basic earnings per unit calculation during periods in which they receive cash distributions.  We are required to pay in-kind distributions to the Series A Preferred Units for the first four full quarters beginning the quarter ended June 30, 2013, and continuing until the Series A Preferred Units have been converted into common units (See Note 9). Because the Series A Preferred Units have 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 Second Amended and Restated Agreement of Limited Partnership (“Partnership Agreement”) requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our General Partner. We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.40 per unit to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our General Partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter.
 
Paid In-Kind Distributions
 
During the second quarter of 2013, we raised $40.0 million of equity through issuances of 1,715,000 Series A Preferred Units and an additional General Partner contribution to satisfy the requirements of the second amendment to our $350.0 million Second Amended and Restated Credit Agreement with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders (as amended, our “Credit Facility”) (See Note 6 and Note 9). Under the terms of our Partnership Agreement, we are 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 determines to begin paying quarterly distributions in cash.  In-kind distributions will be 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) or, beginning after four full quarters, such higher per unit rate as is paid in respect to our common units. Cash distributions will equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common

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unit. In accordance with the Partnership Agreement, our General Partner receives a corresponding distribution of in-kind general partner units to maintain its 2.0% interest in us.
 
The following table represents the paid in-kind (“PIK”) distribution earned for the period ended March 31, 2014 and the PIK distribution for the previous periods (in thousands, except per unit and in-kind distribution units): 
Payment Date
 
Attributable to the Quarter Ended
 
Per Unit Distribution
 
In-Kind Series A
Preferred Unit
Distributions to Series A Preferred Holders
 
In-Kind 
Series A
Preferred
Distributions
Value(3)
 
In-Kind 
Unit
Distribution
to General 
Partner
 
In-Kind General Partner Distribution Value(3)
2014
 
 
 
 
 
 
 
 
 
 
 
 
May 15, 2014
 
March 31, 2014
 
$
0.40

 
31,513

 
$
534

 
643

 
$
11

2013
 
 
 
 
 
 
 
 
 
 
 
 
February 14, 2014
 
December 31, 2013
 
0.40

 
30,971

 
558

 
632

 
11

November 14, 2013
 
September 30, 2013
 
0.40

 
30,439

 
511

 
621

 
10

August 14, 2013
 
June 30, 2013
 
0.35

(1) 
22,276

 
512

 
454

 
10

August 14, 2013
 
June 30, 2013
 
0.20

(2) 
2,199

 
51

 
45

 
1

 
(1) Per unit distribution of $0.35 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the issuance of 1,466,325 Series A Preferred Units and 29,925 general partner units on April 12, 2013.
(2) Per unit distribution of $0.20 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the issuance of 248,675 Series A Preferred Units and 5,075 general partner units on May 15, 2013.
(3) 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 distribution declared for the period ended March 31, 2014 and distributions paid for the prior periods (in thousands, except per unit data): 
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
Attributable to the
 
Per Unit
 
 
 
Limited Partners
 
 
 
 
Payment Date
 
Quarter Ended
 
Distribution
 
 
 
Common
 
Subordinated
 
General Partner
 
Total
2014
 
 
 
 

 
 
 
 

 
 

 
 

 
 

May 15, 2014
 
March 31, 2014
 
$
0.40

 
 
 
$
8,586

 
$
4,885

 
$
290

 
$
13,761

2013
 
 
 
 
 

 
 
 
 
 
 
 
 
February 14, 2014
 
December 31, 2013
 
0.40

 

 
8,581

 
4,885

 
289

 
13,755

November 14, 2013
 
September 30, 2013
 
0.40

 
 
 
4,888

 
4,885

 
214

 
9,987

August 14, 2013
 
June 30, 2013
 
0.40

 
 
 
4,890

 
4,886

 
210

 
9,986

May 15, 2013
 
March 31, 2013
 
0.40

 
 
 
4,888

 
4,886

 
199

 
9,973

2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
February 14, 2013
 
December 31, 2012
 
0.24

 
(1) 
 
2,931

 
2,931

 
120

 
5,982


(1) Per unit distribution of $0.24 corresponds to the minimum quarterly distribution of $0.40 per unit, or $1.60 on an annualized basis, pro-rated for the portion of the quarter following the closing of our initial public offering on November 7, 2012.

Also, in accordance with our long-term incentive plan, we pay distribution equivalent rights to holders of units granted under that plan that vest during the year (See Note 11).

4. FINANCIAL INSTRUMENTS

Fair Value Measurements

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We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:
•
Level 1—Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes our cash and cash equivalents, accounts receivable and accounts payable.
•
Level 2—Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes variable rate debt, OTC swap contracts based upon natural gas price indices and interest rate swaps.
•
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.
Derivative Financial Instruments
Interest Rate Swaps
We manage a portion of our interest rate risk through interest rate swaps. In March 2012, we terminated an interest rate cap contract and entered into an interest rate swap contract with Wells Fargo, N.A. to reduce the risk associated with the variability of interest rates for our term loan borrowings. The interest rate swap has a notional value of $150.0 million, and a maturity date of June 30, 2014. We receive a floating rate based upon one-month LIBOR and pay a fixed rate under the interest rate swap of 0.54%. 

The fair value of our interest rate swap is determined based on a discounted cash flow method using the contractual terms of the swap. The floating coupon rate is based on observable rates consistent with the frequency of the interest cash flows. As of March 31, 2014 and December 31, 2013, the current portion of the interest rate swap liability of $0.1 million and $0.3 million, respectively, was included within other current liabilities. As of March 31, 2014 and December 31, 2013, there was no non-current portion of the interest rate swap liability.
 
The fair value of the interest rate swap liabilities were as follows (in thousands):
 
 
Significant Other Observable Inputs (Level 2)
 
Fair value measurement as of
 
March 31, 2014
 
December 31, 2013
Interest rate swap liabilities
$
145

 
$
263

 
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 and 2013.
 
The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and comprehensive loss were as follows (in thousands):

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Three Months Ended March 31,
 
2014
 
2013
Change in value recognized in other comprehensive loss - effective portion
$
(11
)
 
$
(69
)
Loss reclassified from accumulated other comprehensive loss to interest expense
115

 
94

 
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. We estimate that approximately $0.1 million of hedging losses related to the interest rate swap contract will be reclassified from accumulated other comprehensive income (loss) into statements of operations within the next 12 months.
 
The interest rate swap was being accounted for as a cash flow hedge until February 2014, at which time we discontinued cash flow hedge accounting on a prospective basis, as a result of the $148.5 million temporary repayment of borrowings under our Credit Facility (See Note 10). 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 will be reclassified into interest expense as interest on the hedged debt is 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 will be recognized in interest expense unless a new cash flow hedging relationship is designated.

The 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,
 
2014
 
2013
Realized loss on interest rate derivative
$
27

 
$
27

Unrealized loss on interest rate swap derivative
12

 
—

 
Commodity Swaps
 
In our normal course of business, we periodically enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. The total volume for the outstanding month-ahead swap contracts as of March 31, 2014 and December 31, 2013 was 49,150 MMBtu per day and 33,722 MMBtu per day, respectively. We define these contracts as Level 2 because the index price associated with such contracts is observable and tied to a similarly quoted first-of-the-month natural gas index price. As of March 31, 2014 and December 31, 2013, the fair value of $0.2 million and $0.1 million was included within other current assets, respectively.

We have elected to present our commodity swaps net in the balance sheet. We did not have any cash collateral received or paid on our commodity swaps as of March 31, 2014. The effect of offsetting in our balance sheet was as follows (in thousands):
 
 
March 31, 2014
 
December 31, 2013
 
 
Other Current Assets
 
Other Current Liabilities
 
Other Current Assets
 
Other Current Liabilities
Gross Amounts of Recognized Assets / (Liabilities)
 
$
164

 
$
—

 
$
140

 
$
(20
)
Gross Amounts Offset in the Balance Sheet
 
—

 
—

 
(20
)
 
20

Net Amount
 
$
164

 
$
—

 
$
120

 
$
—

The realized and unrealized gain/(loss) on these derivatives, recognized in revenues in our statements of operations were as follows (in thousands):
 
Three Months Ended March 31,
 
2014
 
2013
Realized gain/(loss) on derivatives
$
(1,169
)
 
$
(46
)
Unrealized gain/(loss) on derivatives
44

 
—


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5. LONG-LIVED ASSETS
Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
 
Estimated
Useful Life (yrs)
 
March 31, 2014
 
December 31, 2013
Pipelines
30
 
$
381,052

 
$
344,721

Gas processing, treating and other plants
15
 
258,101

 
254,133

Compressors
7
 
20,144

 
20,030

Rights of way and easements
15
 
24,998

 
20,729

Furniture, fixtures and equipment
5
 
3,428

 
3,347

Capital lease vehicles
3-5
 
1,703

 
1,396

    Total property, plant and equipment
 
 
689,426

 
644,356

Accumulated depreciation and amortization
 
 
(88,414
)
 
(79,908
)
    Total
 
 
601,012

 
564,448

Construction in progress
 
 
10,960

 
6,039

Land and other
 
 
5,190

 
5,308

    Property, plant and equipment, net
 
 
$
617,162

 
$
575,795

 
Depreciation is provided using the straight-line method based on the estimated useful life of each asset.  Depreciation expense for the three months ended March 31, 2014 and 2013 was $8.5 million and $7.2 million, respectively.
 
Costs related to projects under construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.  For the three months ended March 31, 2014 and 2013, we capitalized interest of $0.1 million and $0.6 million, respectively.
 
In January 2013, we shut down our Gregory facility to perform extensive turnaround maintenance activities and to connect additional equipment to enhance NGL recoveries.  As the turnaround maintenance was nearing completion in January 2013, we experienced a fire at this facility.  In connection with the fire, we spent approximately $5.3 million to return the plant to service and filed an insurance claim related to these costs.  We recovered $1.0 million from insurance for this loss during the second quarter of 2013 and believe it is probable that we will recover the remaining costs, less a $0.3 million deductible, under our insurance policies.
 
Intangible Assets

Intangible assets of $1.6 million as of March 31, 2014 and 2013 represent the unamortized value assigned to the 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. Amortization expense in the consolidated financial statements presented and over the next five years related to intangible assets for the periods presented is not material.

6. LONG-TERM DEBT 

Credit Facility
 
In November 2012, we entered into the Credit Facility, which matures on November 7, 2017. We may utilize the Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions and other general purposes. Our outstanding debt is as follows:
 
March 31, 2014
 
December 31, 2013
Credit Facility, due November 2017
$
170,850

 
$
267,300

Total long-term debt
$
170,850

 
$
267,300

Our Credit Facility contains various covenants and restrictive provisions and requires maintenance of certain financial and operational compliance covenants. As of March 31, 2014 and December 31, 2013, we were in compliance with all of our

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loan covenants. All of our assets are pledged as collateral under our Credit Facility. The terms of our Credit Facility contain customary covenants, including those that restrict our ability to make or limit certain payments, distributions, acquisitions, loans, or investments, incur certain indebtedness or create certain liens on its assets, consolidate or enter into mergers, dispose of certain of our assets, engage in certain types of transactions with its affiliates, enter into certain sale/leaseback transactions and modify certain material agreements.
Borrowings under our Credit Facility bear interest at LIBOR plus an applicable margin or a base rate as defined in the respective credit agreements. Under the terms of the Credit Facility, the applicable margin under LIBOR borrowings was 2.5% and 3.3% at March 31, 2014 and 2013, respectively. The weighted-average interest rate for the three months ended March 31, 2014 and the three months ended March 31, 2013 was 4.6% and 3.5%, respectively.
 
Under our Credit Facility, we have the ability to borrow up to $350.0 million less any letters of credit outstanding. As of March 31, 2014, our borrowings under the Credit Facility were $170.9 million, our letters of credit outstanding were $24.5 million and our remaining unused borrowings under the Credit Facility were $154.7 million. For the three months ended March 31, 2014 and 2013, our average outstanding borrowings were $192.4 million and $229.8 million, respectively, and for the three months ended March 31, 2014 and 2013, our maximum outstanding borrowings were $267.3 million and $246.0 million.

The fair value of the debt funded through our Credit Facility approximates its carrying amount as of March 31, 2014 and December 31, 2013 due primarily to the variable nature of the interest rate of the instrument.

Amendments to Credit Facility

During the fourth quarter of 2012 and into the first quarter of 2013 we encountered operational challenges including the January 2013 fire at our Gregory facility and contractual disputes with a former third party processor. These items impacted our operating results adversely and resulted in the need to amend our Credit Facility with the First Amendment and the Second Amendment (as described below). Due to the benefits from an equity raise during the first quarter of 2014 and improved financial performance, we entered into the Third Amendment and the Fourth Amendment (as described below), respectively, which reverted certain terms of the Credit Facility back to the original terms.

First Amendment to Credit Facility

On March 27, 2013, we entered into the first amendment (the “First Amendment”) to the Credit Facility. As a result of the First Amendment, our available credit 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 (the “Collateral Account”) and letters of credit outstanding. Amounts on deposit in the Collateral Account were pledged as collateral to the Credit Facility. Pursuant to the First Amendment, we were permitted to pay our quarterly cash distribution of available cash for the first quarter of 2013 regardless of whether we met certain financial covenants for the period ending March 31, 2013. Because the First Amendment did not modify our requirement to meet the financial covenants under the Credit Facility beginning March 31, 2013, and because we believed it was unlikely that we would be in compliance with our financial covenants for the quarter ending March 31, 2013, we further amended our Credit Facility as discussed below.  In connection with the First Amendment, we incurred $0.6 million in fees, which were deferred and are being amortized over the remaining life of the Credit Facility.
 
Second Amendment to Credit Facility

On April 12, 2013, we entered into the limited waiver and second amendment (the “Second Amendment”) to the Credit Facility, which waived our defaults relating to financial covenants in the Credit Facility for the period ended March 31, 2013 and provided more favorable financial covenants until we provided notice under the Credit Facility that we have achieved a consolidated total leverage ratio (the “Target Leverage Ratio”) of 4.25 to 1.00 for one quarter or 4.50 to 1.00 for two consecutive quarters, calculated excluding the benefit of cash on deposit in the Collateral Account and any equity cure amounts (the “Target Leverage Test”). See the Fourth Amendment discussion below regarding the Target Leverage Test. Our available credit, excluding our letters of credit, continued to be subject to the availability limits described in the First Amendment. In connection with the Second Amendment, we incurred $1.5 million in fees, which were deferred and are being amortized over the remaining life of the Credit Facility.

The Second Amendment provided for, among other things, the following: 
•
established our letters of credit sublimit at $50.0 million;  
•
until we achieved the Target Leverage Ratio:
•
an increase in our interest rate to LIBOR plus 4.50%;

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•
a limit to our growth capital expenditures of $25.0 million for the last three quarters of 2013 and an additional $25.0 million for the subsequent 18-months ending June 30, 2015 (provided that if additional cash, as required under the Second Amendment, is placed in the Collateral Account, such expenditures could have been increased to $28.0 million for the remaining three quarters of 2013 and the subsequent 18-months ending June 30, 2015); 
•
distributions to our unitholders were effectively limited to our established minimum quarterly distribution of $0.40 per unit; and 
•
our ability to make acquisitions was limited; and
•
once we achieved the Target Leverage Ratio, we had the option to revert certain provisions of the Credit Facility back to the terms of our original Credit Facility (See Fourth Amendment to Credit Facility below).
Third Amendment to Credit Facility
On January 29, 2014, we entered into the Third Amendment (the “Third Amendment”) to our Credit Facility.
Pursuant to the Third Amendment, we were able to (a) acquire a specified target entity or its assets, provided that, among other things, the aggregate consideration paid by us in connection with such acquisition did not exceed $40.0 million and (b) make certain capital expenditures with respect to the addition to our pipeline systems into Webb County, Texas (the “Webb Pipeline”).

In addition, the Third Amendment decreased our Maximum Adjusted Consolidated Total Leverage Ratio (as defined in our Credit Facility) to 5.75 to 1.00 for the March 31, 2014 calculation period when we (a) received net cash proceeds in a specified amount pursuant to permitted equity offerings and (b) initiated construction of the Webb Pipeline in accordance with the terms of our Credit Facility. In connection with the Third Amendment, we incurred $0.1 million in fees, which were deferred and are being amortized over the remaining life of the Credit Facility.

Fourth Amendment to Credit Facility
On March 13, 2014, we entered into the Fourth Amendment (the “Fourth Amendment”) to the Credit Facility. Concurrently with the Fourth Amendment becoming effective, we exercised the Target Leverage Option established pursuant to the Second Amendment and satisfied a leverage ratio of less than 4.25 to 1.00 calculated on a pro forma basis for the debt outstanding, after the net proceeds from the equity issuance were used to pay off debt, and utilizing the Adjusted EBITDA, as provided in the Fourth Amendment, for the period ended December 31, 2013. An effect of us exercising the Target Leverage Option was the removal of the $250.0 million availability limit as provided for in the First Amendment and returning the availability under the Credit Facility to its original $350.0 million, less any letters of credit outstanding.
Pursuant to the Fourth Amendment, all funds previously deposited in the Collateral Account were released from the liens and security interests and are no longer pledged as collateral securing our obligations under the Credit Facility.
As a result of the Fourth Amendment and our exercise of the Target Leverage Option, certain other provisions of the Credit Facility reverted to the requirements and terms in effect before the Second Amendment. The effects of such reversion are that, among other things, (a) the Applicable Margin has been reset to the current applicable level in the pricing grid based on our pro forma Consolidated Total Leverage immediately upon closing of the Fourth Amendment, (b) the $25.0 million limit on growth capital expenditures for the 18-month period ending June 30, 2015 is no longer effective and (c) certain limitations on unit distributions imposed by the Second Amendment are no longer effective. In connection with the Fourth Amendment, we incurred $0.1 million in fees, which were deferred and are being amortized over the remaining life of the Credit Facility.

Concurrently with the Fourth Amendment and as a result of our acquisition in March 2014, our maximum consolidated total leverage ratio was increased to 5.00 to 1.00 through September 30, 2014.

The Credit Facility contains various covenants and restrictive provisions and also requires maintenance of certain financial and operational covenants including but not limited to the following:

•
beginning October 1, 2014 and prior to exercising a one-time covenant election in connection with the issuance of certain unsecured notes, a consolidated total leverage ratio (generally defined as debt to EBITDA, as adjusted) of not more than 4.50 to 1.00, and a consolidated interest coverage ratio of not less than 2.50 to 1.00. The requirement to maintain a certain consolidated total leverage ratio is subject to a provision for increases to 5.00 to 1.00 in connection with certain acquisitions; and


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•
upon exercising a one-time covenant election in connection with the issuance of certain unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.00, a consolidated senior secured leverage ratio of not more than 3.50 to 1.00 and a consolidated interest coverage ratio of not less than 2.50 to 1.00.

7. COMMITMENTS AND CONTINGENCIES
 
Legal Matters
 
On March 5, 2013, our subsidiary filed suit against Formosa Hydrocarbons Company, Inc. (“Formosa”).  The lawsuit seeks recoveries of losses that we believe our subsidiary experienced as a result of the failure of Formosa to perform certain of its obligations under the gas processing and sales contract between the parties.  Formosa filed a response generally denying our claims and, later, Formosa filed a counterclaim against our subsidiary claiming our affiliate breached the gas processing and sales contract and a related agreement between the parties for the supply by Formosa of residue gas to a third party on behalf of our subsidiary. We believe the counterclaims are without merit and our subsidiary will defend itself vigorously against the counterclaims while continuing to pursue its own claims. We cannot predict the outcome of such litigation or the timing of any related recoveries or payments.
 
From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. There currently are no such pending proceedings to which we are a party that our management believes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims ultimately will have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.
 
Regulatory Compliance
 
In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition.
 
Leases

Capital Leases
 
We have auto leases classified as capital leases that are recorded in other current liabilities and other non-current liabilities in our consolidated balance sheet as of March 31, 2014. The lease termination dates of the agreements vary from 2014 until 2018. We recorded amortization expense related to the capital leases of $0.1 million for the three months ended March 31, 2014. We had no capital lease amortization during the three months ended March 31, 2013.

Capital leases entered into during the three months ended March 31, 2014 were $0.3 million.

Operating Leases
 
We maintain operating leases in the ordinary course of business.  These leases include those for office and other operating facilities and equipment.  The lease termination dates of the agreements vary from 2014 to 2017.  Expenses associated with operating leases were $0.3 million and $0.5 million for the three months ended March 31, 2014 and 2013, respectively.

Purchase Commitments
 
At March 31, 2014, we had commitments of approximately $52.3 million to purchase equipment related to our capital 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. TRANSACTIONS WITH RELATED PARTIES
 
Charlesbank
 
The current board of directors of our General Partner includes three persons affiliated with Charlesbank and three outside directors. All of these directors are compensated equally for similar responsibilities and reimbursed for expenses incurred for

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their services to us. For the three months ended March 31, 2014 and 2013, we paid fees related to the Charlesbank director services of $0.1 million and $0.3 million, respectively, which are reflected in general and administrative expenses in our consolidated statements of operations.
 
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.  During the three months ended March 31, 2014 and 2013, we incurred expenses of $7.4 million and $5.9 million, respectively, related to these reimbursements, which are reflected in operating expenses in our consolidated statements of operations.
 
The reimbursement of our compensation expenses to our General Partner began on January 1, 2013 in accordance with our Partnership Agreement.
 
During the second quarter of 2013, we entered into a Purchase Agreement (as defined below) 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 Series A Preferred Unit, in a privately negotiated transaction (See Note 9).  After the Series A Preferred Units issuance during the second quarter of 2013, Southcross Energy LLC sold 1,500,000 of the units to third parties. Southcross Energy LLC currently holds 225,766 Series A Preferred Units.  See Note 6 for discussion of the Collateral Account held by our General Partner.
Wells Fargo Bank, N.A.
During the three months ended March 31, 2014, we entered into amendments to our Credit Facility with syndicates of financial institutions and other lenders. These syndicates included affiliates of Wells Fargo Bank, N.A., an affiliate of which is a member of the investor group (See Note 6). 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. Total fees paid, excluding interest, to affiliates of Wells Fargo, N.A. and its affiliates were $0.2 million during the three months ended March 31, 2014.
 
9. SERIES A PREFERRED UNITS
 
We entered into a Series A Convertible Preferred Unit Purchase Agreement (the “Purchase Agreement”) with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC during the second quarter of 2013 for a cash purchase price of $22.86 per unit, in a privately negotiated transaction (the “Private Placement”). Southcross Energy LLC sold 1,500,000 of these Series A Preferred Units to third parties during the second quarter of 2013.

Our total capital infusion of $40.0 million, from all sales of Series A Preferred Units and General Partner capital contributions, was used to reduce borrowings under our Credit Facility (See Note 6). The Private Placement of Series A Preferred Units resulted in proceeds to us of $39.2 million. We also received a $0.8 million capital contribution from our General Partner to maintain its 2.0% general partner interest in us.
 
Applicable accounting guidance related to the Series A Preferred Units requires that equity instruments with redemption features that are redeemable at the option of the holder be classified outside of permanent equity.  The change of control rights associated with the Series A Preferred Units requires the units to be classified outside of permanent equity.  The Series A Preferred Units were adjusted to maximum redemption value as of March 31, 2014 because the maximum redemption value is currently different than the fair value of the units at issuance.  The adjustment in the valuation adjustment to issuance value and the distributions associated with the Series A Preferred Units of $0.5 million have been included in the calculation of partners’ capital and earnings per unit for the three months ended March 31, 2014.  Additionally, none of the identified embedded derivatives relating to the terms of the Series A Preferred Units require bifurcation, as each embedded derivative was determined to be clearly and closely related to the host contract.
 
Voting Rights: The Series A Preferred Units are a class of voting equity security that ranks senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation.  The Series A Preferred Units have voting rights identical to the voting rights of the common units and vote with the common units as a single class, such that each Series A Preferred Unit (including each Series A Preferred Unit issued as an in-kind distribution, discussed below) is entitled to one vote for each common unit into which such Series A Preferred Unit is convertible on each matter with respect to which each common unit is entitled to vote.

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Distribution Rights: Holders of Series A Preferred Units are entitled to quarterly distributions of in-kind Series A Preferred Units for the first four full quarters following the issue date of those units and continuing thereafter until the board of directors of our General Partner determines to begin paying quarterly distributions in cash, and thereafter in cash. In-kind distributions will be 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) or, beginning after four full quarters, such higher per unit rate as is paid in respect of our common units. Cash distributions will equal the greater of $0.40 per unit per quarter or the quarterly distribution paid with respect to each common unit.
 
Conversion Rights: Beginning on January 1, 2015, Series A Preferred Units (including Series A Preferred Units issued as in-kind distributions) will be convertible into common units on a one-for-one basis, except that conversion will be prohibited to the extent that it would cause (on a pro forma basis) our estimated quarterly distributions over any of the succeeding four quarters to exceed our total distributable cash flow in that quarter. Additionally, on January 1, 2015, we will have the right at any time to convert all or some of the Series A Preferred Units (including Series A Preferred Units issued as in-kind distributions) then outstanding into common units if (i) the daily volume-weighted average trading price of the common units on the national securities exchange on which the common units are listed or admitted to trading for the trailing 30-trading-day period before our notice of conversion is greater than 130.0% of the unit purchase price for the Series A Preferred Units, (ii) the average daily trading volume of common units on the securities exchange exceeds 40,000 common units for those 30 trading days and (iii) the conversion would not cause (on a pro forma basis) our estimated quarterly distributions over any of the succeeding four quarters to exceed our total distributable cash flow in that quarter.  Further, the Series A Preferred Units will be convertible into common units based on an exchange ratio of 110.0% of the Series A Preferred Units if a third party acquires majority ownership control of our General Partner or we sell substantially all of our assets, in either case before January 1, 2015.
 
Dissolution and Liquidation: The Series A Preferred Units are senior to our common units with respect to rights on dissolution and liquidation. Common units issued upon conversion of Series A Preferred Units will rank equally with the rest of our common units with respect to rights on dissolution and liquidation.
 
10. PARTNERS’ CAPITAL
 
Common Units
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 net proceeds from the public offering of common units were $144.7 million. The net proceeds from the offering are being used to fund the construction of our new pipeline extending into Webb County, Texas, were used for our acquisition in March 2014 and are being used for general partnership purposes. Pending use of the funds, we temporarily repaid borrowings under our Credit Facility, which we are redrawing to fund the construction of the new pipeline and for other general purposes.
Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement. We had 21,454,119 and 12,253,985 common units issued and outstanding as of March 31, 2014 and December 31, 2013, respectively.
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. We had 12,213,713 subordinated units issued and outstanding as of March 31, 2014 and December 31, 2013.
 
General Partner Interests
 
Our general partner interest consisted of 723,852 general partner units as of March 31, 2014 and 534,638 general partner units as of December 31, 2013. In connection with other equity issuances, 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 3).

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11. INCENTIVE COMPENSATION
Unit Based Compensation
Long-Term Incentive Plan 
On November 7, 2012, and in connection with our initial public offering, we established our 2012 Long-Term Incentive Plan (“LTIP”), which provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the LTIP vest over a three-year period in equal annual installments in either a common unit or an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by management at its discretion. These awards also include distribution equivalent rights that grant the holder the right to receive an amount equal to the cash distributions on common units during the period the award remains outstanding.
 
The following table summarizes information regarding awards of units granted under the LTIP: 
 
Units
 
Weighted-average fair
value at grant date
Unvested - December 31, 2013
182,673

 
22.55

  Granted units
2,000

 
18.04

  Units recaptured for tax withholdings
(66
)
 
24.41

  Vested units
(134
)
 
24.41

Unvested - March 31, 2014
184,473

 
$
22.51

 
For the three months ended March 31, 2014 and 2013, we granted awards under the LTIP with a grant date fair value of $36 thousand and $15 thousand, respectively, which we have classified as equity awards. As of March 31, 2014 and March 31, 2013, we had total unamortized compensation expense of $3.2 million and $2.9 million, respectively, related to these awards, which we expect to be amortized over the three-year vesting period from each equity awards’ grant date. As of March 31, 2014 and March 31, 2013, we had 1,525,121 and 1,609,900 units, respectively, available for issuance under the LTIP.
 
Unit Based Compensation Expense

The following table summarizes information regarding recognized compensation expense, which is included in general and administrative expense on our consolidated statements of operations (in thousands): 
 
Three Months Ended March 31,
 
2014
 
2013
Unit-based compensation
$
529

 
$
408

Employee Savings Plan
We have employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code ("IRC") whereby employees of our General Partner may contribute a portion of their base compensation to the employee savings plan, subject to limits under the IRC. We provide a matching contribution each payroll period equal to 100% of the employee's contribution up to the lesser of 6% of the employee's pay or $17,500 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in general and administrative expense on our consolidated statements of operations (in thousands): 
 
Three Months Ended March 31,
 
2014
 
2013
Matching contributions expensed for employee savings plan
$
356

 
$
149


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


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Three Months Ended March 31,
 
2014
 
2013
Sales of natural gas
$
145,358

 
$
98,309

Sales of NGLs and condensate
51,874

 
32,419

Transportation, gathering and processing fees
16,115

 
13,345

Other
244

 
177

Total revenues
$
213,591

 
$
144,250

 
13. CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE
 
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, 2014 and 2013 represent the following percentages of consolidated revenue: 
 
Three Months Ended March 31,
 
2014
 
2013
Top ten customers
64.6
%
 
60.3
%
 
The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three months ended March 31, 2014 and 2013 was as follows: 
 
Three Months Ended March 31,
 
2014
 
2013
Trafigura AG
12.2
%
 
(a)

Sherwin Alumina Company
(a)

 
11.7
%
Formosa Hydrocarbons Co., Inc.
(a),(b)

 
12.0
%
 
(a) Information is not provided for periods for which the customer or producer was less than 10% of our consolidated revenue.
(b) Our contract with Formosa terminated on June 1, 2013.
 
For the three months ended March 31, 2014 and 2013, we did not experience significant non-payment for services. At March 31, 2014, we did not record an allowance for uncollectible accounts receivable.
 
14. SUBSEQUENT EVENTS
 
Partnership Distribution
 
On April 24, 2014, the Board of Directors of our General Partner declared a cash distribution of $0.40 per common unit and subordinated unit, including units equivalent to our General Partner’s 2% interest in the Partnership, which will be paid on May 15, 2014 to unitholders of record on May 9, 2014.  Also on April 24, 2014, the Board of Directors of our General Partner declared a Series A Preferred Unit distribution of $0.40 per unit, which will be paid in-kind on May 15, 2014 to unitholders of record on May 9, 2014, and our General Partner will receive a number of general partner units to maintain the General Partner’s 2% interest in the Partnership.

15. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)

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Three Months Ended March 31,
 
2014
 
2013
Supplemental Disclosures:
 
 
 
Cash paid for interest, net of amounts capitalized
$
2,776

 
$
2,478

Cash paid for taxes, net of refunds received
23

 
—

Supplemental schedule of non-cash investing and financing activities:
 
 
 
 Accounts payable related to capital expenditures
1,628

 
22,996

Change in value recognized in other comprehensive income
11

 
69

Capital lease obligation
307

 
—

Accrued distribution equivalent rights (DERs) on the LTIP units
76

 
21

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,
 
2014
 
2013
Total interest costs
$
3,072

 
$
2,649

Capitalized interest included in property, plant and equipment, net
(99
)
 
(602
)
Interest expense
$
2,973

 
$
2,047

Deferred Financing Costs

Deferred Financing costs are capitalized and amortized as interest expense under the effective interest method over the term of the related debt. The unamortized balance of deferred financing costs is included in other assets on the consolidated balance sheets. Changes in deferred financing costs are as follows (in thousands):
 
2014
Deferred financing costs, January 1
$
5,237

Capitalization of deferred financing costs (1)
156

Less:
 
Amortization of deferred financing costs
(337
)
Deferred financing costs, March 31
$
5,056

___________________________________________________________________________
(1) See Note 6.

Southcross Assets Considered Leases to Third Parties

On March 6, 2014 we acquired natural gas pipelines and contracts related to these 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, 2014, were as follows: $3.7 million in 2014 of which a portion was paid prior to our acquisition, $5.6 million in 2015, $5.6 million in 2016, $5.6 million in 2017, $2.2 million in 2018, $2.2 million in 2019 and $15.3 million thereafter. The revenue recognized for the demand payments is recognized on a straight-line basis over the term of the contract. The demand fee revenues under the contracts were $0.2 million for the three months ended March 31, 2014 and have been included within transportation, gathering and processing fees within Note 12. The amounts do not include contingent fees based on the actual gas volumes delivered under the contracts. Contingent fees were $0.1 million for the three months ended March 31, 2014.


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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
Overview and How We Evaluate our 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.” Southcross Energy LLC is a Delaware limited liability company. Southcross Energy LLC holds all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”), all of our subordinated units, as well as a portion of our common units and Series A Convertible Preferred Units (“Series A Preferred Units”) originally issued during the second quarter of 2013. Southcross Energy LLC and its subsidiaries are controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC ("Charlesbank").

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 3 gas processing plants, 2 fractionation plants and approximately 2,800 miles of pipeline. Our South Texas assets are located in or near the Eagle Ford shale region. 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 the resulting NGLs into the various components and selling or delivering pipeline quality natural gas 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

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general commodity price levels of natural gas and NGLs and the volume of NGLs recovered relative to the fixed recovery obligations. 
We assess gross operating margin opportunities across our integrated value stream so that processing margins may be supplemented by gathering and transportation fees and opportunities to sell residue gas and NGLs at fixed-spreads. Gross operating margin earned under fixed-fee and fixed-spread arrangements is directly related to the volume of natural gas that flows through our systems and is generally independent from general commodity price levels. A sustained decline in commodity prices could result in a decline in volumes entering our system and, thus, a decrease in gross operating margin for our fixed-fee and fixed-spread arrangements.
The following table summarizes our gross margins from these arrangements (in thousands):
 
Three Months Ended March 31,
 
2014
 
2013
 
Gross margin
 
Percent of total gross operating margin
 
Gross margin
 
Percent of total gross operating margin
Fixed-fee
$
16,253

 
59.8
%
 
$
13,396

 
71.0
%
Fixed-spread
3,886

 
14.3
%
 
3,499

 
18.6
%
Sub-total
20,139

 
74.1
%
 
16,895

 
89.6
%
Commodity-sensitive
7,049

 
25.9
%
 
1,967

 
10.4
%
Total gross operating margin
$
27,188

 
100.0
%
 
$
18,862

 
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 (i) volume, (ii) gross operating margin, (iii) operations and maintenance expenses, (iv) Adjusted EBITDA and (v) 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 contract 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, plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation and unrealized gains/losses on derivative contracts, major litigation net of recoveries, transaction expense, revenue deferral adjustment and selected charges that are unusual or non-recurring; less interest income, income tax benefit, unrealized gains on commodity derivative contracts and selected gains

27
Table of Contents

that are unusual or non-recurring. A revenue deferral adjustment relates primarily to long-term contracts in which the cash consideration we receive for providing service varies from the revenue recognized during the period. Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP.
Adjusted EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
•
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions;
•
operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
•
the attractiveness of capital projects and acquisitions and the overall rates of return on investment opportunities.
We define distributable cash flow as Adjusted EBITDA, plus interest income, 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. 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) income (in thousands): 

Three Months Ended March 31,

2014
 
2013
Reconciliation of gross operating margin to net loss
 
 
 
Gross operating margin
$
27,188

 
$
18,862

(Deduct):
 
 
 
Income tax expense
(8
)
 
(18
)
Interest expense
(2,973
)
 
(2,047
)
Loss on asset disposal
(4
)
 
—

General and administrative expense
(6,103
)
 
(6,041
)
Depreciation and amortization expense
(8,528
)
 
(7,249
)
Operations and maintenance expense
(10,861
)
 
(9,889
)
Net loss
$
(1,289
)
 
$
(6,382
)


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The following table presents a reconciliation of net cash flows provided by operating activities to net (loss) income, Adjusted EBITDA and distributable cash flow (in thousands): 
 
Three Months Ended March 31,
 
2014
 
2013
Reconciliation of Net Cash Flows Provided by Operating Activities to Net Loss and Adjusted EBITDA
 
 
 
Net cash provided by (used in) operating activities
$
14,176

 
$
(1,711
)
Add (deduct):

 

Depreciation and amortization expense
(8,528
)
 
(7,249
)
Unit-based compensation
(529
)
 
(408
)
Deferred financing costs amortization
(337
)
 
(267
)
Loss on asset disposal
(4
)
 
—

Unrealized gain
32

 
—

Other, net
(14
)
 
—

Changes in operating assets and liabilities:

 

Trade accounts receivable
7,477

 
(8,648
)
Prepaid expenses and other
(813
)
 
(1,199
)
Other non-current assets
25

 
13

Accounts payable and accrued expenses
(13,694
)
 
11,725

Other liabilities
920

 
1,362

Net loss
$
(1,289
)
 
$
(6,382
)
Add (deduct):

 

Depreciation and amortization expense
$
8,528

 
$
7,249

Interest expense
2,973

 
2,047

Income tax expense
8

 
18

Unrealized gain
(32
)
 
—

Revenue deferral adjustment
1,182

 
—

Unit-based compensation
529

 
408

Loss on asset disposal
4

 
—

Major litigation costs, net of recoveries
273

 
—

Transaction expenses for acquisition
303

 
—

Other, net
18

 
—

Expenses associated with significant items
—

 
1,201

Adjusted EBITDA
$
12,497

 
$
4,541

(Deduct):

 

Cash interest, net of capitalized costs
$
(2,615
)
 
$
(1,780
)
Income tax expense
(8
)
 
(18
)
Maintenance capital expenditures
(1,363
)
 
(708
)
Distributable cash flow
$
8,511

 
$
2,035

 
Current Year Highlights
 
The following events took place during the three months ended March 31, 2014 and have impacted, or are likely to impact, our financial condition and results of operations.
 
Public Equity Offering 
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 net proceeds from the public offering of common units were $144.7 million. The net proceeds from the offering are being used to fund the construction of our new pipeline extending into Webb County, Texas, were used to fund our acquisition in March 2014 and are being used for general partnership purposes. Pending use of the funds, we temporarily repaid borrowings under our Credit Facility, which we are redrawing to fund the construction of the new pipeline and for other general purposes.

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Credit Facility
On March 13, 2014, we entered into the Fourth Amendment (the “Fourth Amendment”) to the Second Amended and Restated Credit Agreement, dated as of November 7, 2012, by and among us, as borrower, Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders party thereto (as amended, the “Credit Facility”). Concurrently with the Fourth Amendment becoming effective, we exercised the Target Leverage Option established pursuant to the Second Amendment (the “Second Amendment”) to the Credit Facility and satisfied a leverage ratio of less than 4.25 to 1.00 calculated on a pro forma basis for the debt outstanding and utilizing the EBITDA, adjusted as provided in the Fourth Amendment, for the period ended December 31, 2013. As a result of the Fourth Amendment and our exercise of the Target Leverage Option, certain provisions of the Credit Facility reverted to the requirements and terms in effect before the First Amendment to the Credit Facility (the “First Amendment”) and the Second Amendment, including, but not limited to, the removal of the $250.0 million availability limit as provided for in the First Amendment and returning the availability under the Credit Facility to its original $350.0 million. See further discussion included in Part I, Item 1, Note 6, of this report.
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. In the first quarter of 2014, we expensed $0.3 million of transaction costs associated with the acquisition.

Webb Pipeline Construction

During the first quarter of 2014, we began construction of an addition to our pipeline systems by approximately 90 miles into Webb County, Texas (the “Webb Pipeline”). During the three months ended March 31, 2014, we incurred $5.6 million in capitalized costs related to the Webb Pipeline.


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Results of Operations
 
The following table summarizes our results of operations (in thousands, except operating data): 
 
Three Months Ended March 31,
 
2014
 
2013
Revenues
$
213,591

 
$
144,250

Expenses:


 


Cost of natural gas and liquids sold
186,403

 
125,388

Operations and maintenance
10,861

 
9,889

Depreciation and amortization
8,528

 
7,249

General and administrative
6,103

 
6,041

Loss on asset disposal
4

 
—

Total expenses
211,899

 
148,567

 
 
 
 
Income (loss) from operations
1,692

 
(4,317
)
Interest expense
(2,973
)
 
(2,047
)
Loss before income tax expense
(1,281
)
 
(6,364
)
Income tax expense
(8
)
 
(18
)
Net loss
$
(1,289
)
 
$
(6,382
)
 
 
 
 
Other financial data:
 
 
 
Adjusted EBITDA
$
12,497

 
$
4,541

Gross operating margin
27,188

 
18,862

 
 
 
 
Maintenance capital expenditures
1,363

 
708

Growth capital expenditures
$
9,724

 
$
48,495

 
 
 
 
Operating data:
 
 
 
Average throughput volumes of natural gas (MMBtu/d) (1)
 
 
 
South Texas
443,043

 
431,553

Mississippi/Alabama
222,296

 
203,285

Total average throughput volumes of natural gas
665,339

 
634,838

Average volume of processed gas (MMBtu/d)
246,422

 
239,757

Average volume of NGLs sold (Bbls/d)
14,329

 
10,152

 
 
 
 
Realized prices on natural gas volumes ($/MMBtu)
$
5.07

 
$
3.44

Realized prices on NGL volumes ($/gal)
0.96

 
0.84

 
(1) Current and historical average throughput volumes of natural gas per day include sales, transportation, fuel and shrink volumes. Historical average throughput volumes of natural gas per day presented previously was based on sales and transportation volume only.  

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Volume and overview.  Our average throughput volume of natural gas per day increased 30,501 MMBtu/d to 665,339 MMBtu/d during the three months ended March 31, 2014, compared to 634,838 MMBtu/d during the three months ended March 31, 2013, due primarily to increased gas volumes in Mississippi/Alabama as a result of cold weather during the three months ended March 31, 2014. Processed gas volumes increased 6,665 MMBtu/d to 246,422 MMBtu/d during the three months ended March 31, 2014, compared to 239,757 MMBtu/d during the three months ended March 31, 2013. This increase is due primarily to expanded volumes from the Eagle Ford shale producing area during the three months ended March 31, 2014.

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The average volume of NGLs produced for the three months ended March 31, 2014 was 14,329 Bbls/d, an increase of 4,177 Bbls/d, compared to 10,152 Bbls/d for the three months ended March 31, 2013. This increase was due primarily to the impact of volumes of rich gas processed and enhanced operational efficiency at our facilities during the three months ended March 31, 2014 compared to the three months ended March 31, 2013 when we relied partially on third parties for NGL production.
 
Gross operating margin for the three months ended March 31, 2014 was $27.2 million, compared to $18.9 million for the three months ended March 31, 2013.  This increase of $8.3 million was due primarily to increased processed gas volumes and increased transportation, gathering and processing fees.
 
Adjusted EBITDA increased by $8.0 million to $12.5 million for the three months ended March 31, 2014, compared to $4.5 million for the three months ended March 31, 2013, due to higher volumes and margins from processing and fractionation activities partially offset by higher operating and general and administrative expenses.  We had a net loss of $1.3 million for the three months ended March 31, 2014 compared to net loss of $6.4 million for the three months ended March 31, 2013. Net loss decreased due to higher Adjusted EBITDA, offset by increased interest expense.
 
Revenues.  Our total revenues for the three months ended March 31, 2014 were $213.6 million, compared to $144.3 million for the three months ended March 31, 2013.  This increase of $69.3 million, or 48%, was due primarily to revenue from sales of natural gas increasing by $47.0 million from an increase in realized prices in natural gas as well as additional sales volumes. Additionally, revenue increased from sales of NGLs and condensate by $19.5 million for the three months ended March 31, 2014. The increase was due to higher NGL volumes produced in our facilities and higher NGL prices. Revenue from transportation, gathering and processing fees increased by $2.8 million or 21% for the three months ended March 31, 2014 compared to the same period in 2013, reflecting the results of additional rich gas volumes in 2014.  
 
Cost of natural gas and NGLs sold.  Our cost of natural gas and NGLs sold for the three months ended March 31, 2014 was $186.4 million, compared to $125.4 million for the three months ended March 31, 2013. This increase of $61.0 million, or 49%, was due primarily to higher natural gas prices and increased natural gas volumes purchased, as well as increased NGL volumes purchased and higher NGL prices compared to the same period in 2013.
 
Operations and maintenance expense.  Operations and maintenance expense for the three months ended March 31, 2014 was $10.9 million, compared to $9.9 million for the three months ended March 31, 2013. This increase of $1.0 million, or 10%, was due primarily to increased labor and benefits costs during the three months ended March 31, 2014, offset by a reduction in plant operations and maintenance costs during the three months ended March 31, 2013 compared to the three months ended March 31, 2014.
 
General and administrative (“G&A”) expenses.  G&A expenses for the three months ended March 31, 2014 were $6.1 million, compared to $6.0 million for the three months ended March 31, 2013. This increase of $0.1 million, or 1%, was due primarily to increased expenses related to labor and benefits costs and transaction costs related to the Onyx acquisition, primarily offset by a reduction in legal and professional costs for the three months ended March 31, 2014 compared to the three months ended March 31, 2013.
 
Depreciation and amortization expense.  Depreciation and amortization expense for the three months ended March 31, 2014 was $8.5 million, compared to $7.2 million for the three months ended March 31, 2013.  The increase of $1.3 million, or 18%, was due primarily to depreciation of capital projects placed in service during and after the three months ended March 31, 2013.
 
Interest expense.  For the three months ended March 31, 2014, net interest expense was $3.0 million, compared to $2.0 million for the three months ended March 31, 2013. This increase was due to higher average borrowings and an increase in our weighted average borrowing rate of 4.6% for the three months ended March 31, 2014 compared to 3.5% the three months ended March 31, 2013. The borrowing rate increased in April 2013 as a result of the Second Amendment and subsequently decreased during March 2014 due to the Fourth Amendment and the exercise of the Target Leverage Option.
 
Liquidity and Capital Resources
 
Sources of Liquidity
 
Our primary sources of liquidity have been cash generated from operations, investments by Southcross Energy LLC and other investors, equity raised through issuances of common and Series A Preferred Units and borrowings under our Credit

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Facility. Our primary cash requirements consist of operating and G&A expenses, growth and maintenance capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt, purchases and construction of new assets, businesses acquisitions, and distributions to unitholders.
We expect to fund short term cash requirements, such as operating and G&A expenses and maintenance capital expenditures primarily through operating cash flows. We expect to fund long-term cash requirements, such as for expansion projects and acquisitions, through several sources, including operating cash flows, borrowings under our Credit Facility and issuances of additional equity and debt securities, as appropriate and subject to market conditions. We had restrictions under the Second Amendment to our Credit Facility that limited our ability to fund expansion projects; however, in March 2014 we exercised the Target Leverage Option and entered into the Fourth Amendment to our Credit Facility which removed the limitations on our ability to fund expansion projects, among other revisions. See further discussion included in Part I, Item 1, Note 6, “Long-Term Debt” of this report.
As of March 31, 2014, we had $170.9 million in outstanding borrowings under our Credit Facility. Under our Credit Facility, we have the ability to borrow up to $350.0 million less any letter of credit amounts outstanding. 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 net proceeds from the public offering of common units were $144.7 million. We temporarily repaid borrowings under our Credit Facility, which we have begun to redraw to fund the construction of the Webb Pipeline, the acquisition in March 2014 and other general purposes.
Capital expenditures.    Our business is capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of and will continue to include:
•
growth capital expenditures, which are capital expenditures to expand or increase the efficiency of the existing operating capacity of our assets. Growth capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition; and
•
maintenance capital expenditures, which are capital expenditures that are not considered growth capital expenditures.
 
The following table summarizes our capital expenditures (in thousands):
 
 
Three Months Ended March 31,
 
2014
 
2013
Maintenance capital
$
1,363

 
$
708

Growth capital
9,724

 
48,495

Capital expenditures
$
11,087

 
$
49,203


Our growth capital expenditures during the three months ended March 31, 2014 related primarily to our new pipeline extending into Webb County, Texas. The growth capital expenditures during the three months ended March 31, 2013 primarily related to (i) our Bonnie View NGL fractionation facility completed in February 2013, and (ii) our Bee Line pipeline completed in February 2013.
 
Outlook.  Cash flow is affected by a number of factors, some of which we cannot control. These factors include prices and demand for our services, operational risks, volatility in commodity prices or interest rates, industry and economic conditions, conditions in the financial markets and other factors.
 
Our ability to benefit from growth projects to accommodate strong drilling activity and the associated need for infrastructure assets and services is subject to operational risks and uncertainties such as the uncertainty inherent in some of the assumptions underlying design specifications for new, modified or expanded facilities. These risks also impact third party service providers and their facilities. Delays or under-performance of our facilities or third party facilities may adversely affect our ability to generate cash from operations and comply with our obligations, including the covenants under our debt instruments. In other cases, actual production delivered may fall below volume estimates that we relied upon in deciding to pursue an acquisition or other growth project. Future cash flow and our ability to comply with our debt covenants would likewise be affected adversely if we experienced declining volumes over a sustained period and/or unfavorable commodity prices.
 
We believe that cash from operations, cash on hand and our unused borrowings under our Credit Facility will provide liquidity to meet future short term capital requirements and to fund committed capital expenditures for the remainder of 2014. The sufficiency of these liquidity sources to fund necessary and committed capital needs will be dependent upon our ability to meet our covenant requirements of our Credit Facility. In March 2014, we exercised the Target Leverage Option and entered

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into the Fourth Amendment to the Credit Facility which removed the limitations on our ability to fund expansion projects. As of April 30, 2014, we had $152.8 million of unused borrowings under our Credit Facility. We believe we have and will continue to have sufficient liquidity to operate our business. Please see Part I, Item 1, Note 6, “Long-Term Debt” of this report for a description of our Credit Facility.
Growth projects and acquisitions are key elements of our business strategy. We intend to finance our growth capital primarily through the issuance of debt and equity. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate acquisitions or capital projects, we may require access to additional capital. Our access to capital over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets and other financial and business factors, many of which are beyond our control.
Cash Flows
 
The following table provides a summary of our cash flows by category (in thousands): 
 
Three Months Ended March 31,
 
2014
 
2013
Net cash provided by (used in) operating activities
$
14,176

 
$
(1,711
)
Net cash used in investing activities
(50,416
)
 
(52,028
)
Net cash provided by financing activities
37,325

 
48,499

 
Operating cash flows — Net cash provided by operating activities was $14.2 million for the three months ended March 31, 2014, compared to $1.7 million net cash used in operating activities for the three months ended March 31, 2013.  The increase in cash from operating activities was the result of lower net loss during the three months ended March 31, 2014 compared to three months ended March 31, 2013.  Also, the timing of payments for accounts receivable and accounts payable resulted in a $9.3 million increase in net cash provided by operating activities for the three months ended March 31, 2014 compared to three months ended March 31, 2013.

Investing cash flows — Net cash used in investing activities for the three months ended March 31, 2014 was $50.4 million, compared to $52.0 million for the three months ended March 31, 2013.  The decrease of $1.6 million primarily relates to the significant capital expenditures during the first quarter of 2013 including the completion of the Bee Line pipeline and costs related to the ramp-up of the Bonnie View fractionation facility. The first quarter of 2014 had fewer capital expenditures than the previous year, but it included the $38.6 million acquisition of Onyx. During the three months ended March 31, 2014, we spent $9.7 million in growth capital and $1.4 million in maintenance capital. 
 
Financing cash flows — Net cash provided by financing activities for the three months ended March 31, 2014 was $37.3 million, compared to $48.5 million for the three months ended March 31, 2013.  The decrease was due to increased distributions paid of $7.8 million, because the distribution paid during the three months ended March 31, 2013 was pro-rated for the initial public offering timing and the number of units outstanding increased during the three months ended March 31, 2014 resulting in additional distributions. The funding raised from the equity offering during the three months ended March 31, 2014 was used to repay the borrowings under the Credit Facility.
 
Off-Balance Sheet Arrangements
 
We have no off-balance sheet arrangements.
 
Recent Accounting Pronouncements
 
For information on new accounting pronouncements, see Part I, Item 1, Note 1 of this report.
 
Critical Accounting Policies and Estimates
 
Our critical accounting policies are described in our 2013 Annual Report on Form 10-K.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no significant changes to our critical accounting policies since our 2013 Annual Report on Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk.
 
There have been no material changes to our quantitative and qualitative disclosures about market risk described in Item 7A to our 2013 Annual Report on Form 10-K.
 
Item 4.  Controls and Procedures.
 
Disclosure controls and procedures.  The Chief Executive Officer and Chief Financial Officer of our General Partner, who have responsibility for our management, have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of the end of the period covered by this report (the “Evaluation Date”). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner have concluded that, as of the Evaluation Date, our disclosure controls and procedures are effective.
 
Internal control over financial reporting.  There have been no changes in internal controls over financial reporting (as defined in Rule 13a—15(f) or Rule 15d—15(f) of the Exchange Act) during the first fiscal quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
PART II — OTHER INFORMATION
 
Item 1.  Legal Proceedings.
 
A description of our material legal proceedings is included in Part I, Item 1, Note 7, “Commitments and Contingencies – Legal Matters” of this report, and is incorporated herein by reference.

Item 1A. Risk Factors.
 
The risk factors contained in our 2013 Annual Report on Form 10-K under Part 1A “Risk Factors” are incorporated herein by reference. There have been no material changes in our risk factors since that report.
 
These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, results of operations, and financial condition and ability to make distributions.
 
Item 6. Exhibits.
 
The information set forth in the Index to Exhibits accompanying this report is incorporated into this Item 6 by reference.


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

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INDEX TO EXHIBITS
Exhibit
 
 
Number
 
Description
3.1
 
Certificate of Limited Partnership of Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.2
 
Second Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of April 12, 2013 (incorporated by reference to Exhibit 3.3 to our Annual Report on Form 10-K dated April 15, 2013).
3.4
 
Certificate of Formation of Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).
3.5
 
Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of November 7, 2012 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K dated November 7, 2012).
4.1
 
Registration Rights Agreement, dated as of April 12, 2013, by and between Southcross Energy Partners, L.P. and Southcross Energy LLC (incorporated by reference to Exhibit 4.1 to our Annual Report on Form 10-K dated April 15, 2013).
10.1
 
Fourth Amendment to Second Amended and Restated Credit Agreement, dated March 13, 2014, by and among Southcross Energy Partners, L.P., as borrower, Wells Fargo Bank, N.A., as administrative agent thereunder, and each of the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 13, 2014).
10.2
 
Severance Agreement, dated March 3, 2014, by and between Southcross Energy Partners GP, LLC and John E. Bonn (incorporated by reference to Exhibit 10.13 to our Annual Report on Form 10-K dated March 5, 2014).
31.1
 
Certification of Chief Executive Officer required by Rule 13a-14(a)/15d-14(a).
31.2
 
Certification of Chief Financial Officer required by Rule 13a-14(a)/15d-14(a).
32.1
 
Certifications of Chief Executive Officer and Chief Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
101.INS
 
XBRL Instance Document.
101.SCH
 
XBRL Taxonomy Extension Schema.
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
101.PRE
 
XBRL Extension Presentation Linkbase.
 

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

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