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EX-32.1 - EXHIBIT 32.1 - Southcross Energy Partners, L.P.a2016q210-qex321.htm
EX-31.2 - EXHIBIT 31.2 - Southcross Energy Partners, L.P.a2016q210-qex312.htm
EX-31.1 - EXHIBIT 31.1 - Southcross Energy Partners, L.P.a2016q210-qex311.htm
EX-10.1 - EXHIBIT 10.1 - Southcross Energy Partners, L.P.a2016q210-qex101.htm
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 June 30, 2016
 
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.)
 
1717 Main Street, Suite 5200
Dallas, TX
 
75201
(Address of principal executive offices)
 
(Zip Code)
 
(214) 979-3700
(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
 
As of August 2, 2016, the registrant has 36,923,934 common units outstanding, 12,213,713 subordinated units outstanding and 16,522,484 Class B Convertible Units outstanding.  Our common units trade on the NYSE under the symbol “SXE.”



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

/gal: Per gallon
 
Bbls: Barrels
 
Condensate: Hydrocarbons that are produced from natural gas reservoirs but remain liquid at normal temperature and pressure
 
MMBtu: One million British thermal units

Mcf: One thousand cubic feet

MMcf: One million cubic feet
 
NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate
 
Residue gas: Pipeline quality natural gas remaining after natural gas is processed and NGLs and other matters are removed
 
Rich gas: Natural gas that is high in NGL content
 
Throughput: The volume of natural gas and NGLs transported or passing through a pipeline, plant, terminal or other facility
 
Y-grade: Commingled mix of NGL components extracted via natural gas processing normally consisting of ethane, propane, isobutane, normal butane and natural gasoline

2


FORM 10-Q
TABLE OF CONTENTS
Southcross Energy Partners, L.P.
 
 
 
 
 
 
 
 
Condensed Consolidated Balance Sheets as of June 30, 2016 and December 31, 2015
 
 
 
 
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2016 and 2015
 
 
 
 
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2016 and 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

3


PART I — FINANCIAL INFORMATION
 
Item 1. Financial Statements.
 
SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit data)
(Unaudited)
 
June 30, 2016
 
December 31, 2015
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
4,859

 
$
11,348

Trade accounts receivable
29,860

 
39,585

Accounts receivable - affiliates
16,269

 
49,734

Prepaid expenses
2,576

 
3,915

Deposits to suppliers
3,837

 

Other current assets
961

 
1,256

Total current assets
58,362

 
105,838

 
 
 
 
Property, plant and equipment, net
1,034,266

 
1,066,001

Investments in joint ventures
138,461

 
140,526

Other assets
1,675

 
6,595

Total assets
$
1,232,764

 
$
1,318,960

 
 
 
 
LIABILITIES AND PARTNERS' CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
36,081

 
$
66,458

Accounts payable - affiliates
7,304

 
7,871

Current portion of long-term debt
4,500

 
4,500

Other current liabilities
6,472

 
10,406

Total current liabilities
54,357

 
89,235

 
 
 
 
Long-term debt
552,685

 
604,518

Other non-current liabilities
10,341

 
3,871

Total liabilities
617,383

 
697,624

 
 
 
 
Commitments and contingencies (Note 7)
 
 
 
 
 
 
 
Partners' capital:
 
 
 
Common units (36,902,492 and 28,420,619 units outstanding as of June 30, 2016 and December 31, 2015, respectively)
274,990

 
271,236

Class B Convertible units (16,522,484 and 15,958,990 units issued and outstanding as of June 30, 2016 and December 31, 2015)
295,801

 
300,596

Subordinated units (12,213,713 units issued and outstanding as of June 30, 2016 and December 31, 2015)
32,995

 
37,920

General partner interest
11,595

 
11,584

Total partners' capital
615,381

 
621,336

Total liabilities and partners' capital
$
1,232,764

 
$
1,318,960

 
See accompanying notes.

4


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except for per unit data)
(Unaudited)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016

2015
 
2016
 
2015
Revenues:
 
 
 
 
 
 
 
Revenues
$
100,141

 
$
146,129

 
$
195,596

 
$
324,620

Revenues - affiliates
24,561

 
21,091

 
48,832

 
28,538

Total revenues
124,702

 
167,220

 
244,428

 
353,158

 
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 

 
 

Cost of natural gas and liquids sold
85,619

 
124,595

 
165,066

 
265,710

Operations and maintenance
19,615

 
19,834

 
36,393

 
42,388

Depreciation and amortization
18,908

 
17,571

 
37,449

 
34,603

General and administrative
8,162

 
9,003

 
16,048

 
16,809

Impairment of assets

 
193

 

 
193

Loss (gain) on sale of assets, net
(12,576
)
 
(38
)
 
(12,576
)
 
180

Total expenses
119,728

 
171,158

 
242,380

 
359,883

 
 
 
 
 
 
 
 
Income (loss) from operations
4,974

 
(3,938
)
 
2,048

 
(6,725
)
Other expense:


 


 


 


Equity in losses of joint venture investments
(3,534
)
 
(3,604
)
 
(6,963
)
 
(7,155
)
Interest expense
(8,833
)
 
(7,900
)
 
(18,003
)
 
(15,398
)
Total other expense
(12,367
)
 
(11,504
)
 
(24,966
)
 
(22,553
)
Loss before income tax benefit (expense)
(7,393
)
 
(15,442
)
 
(22,918
)
 
(29,278
)
Income tax benefit (expense)
(3
)
 
(9
)
 
3

 
(78
)
Net loss
$
(7,396
)
 
$
(15,451
)
 
$
(22,915
)
 
$
(29,356
)
General partner unit in-kind distribution
(26
)
 
(61
)
 
(26
)
 
(137
)
Net loss attributable to Holdings

 
(1,103
)
 

 
(4,258
)
Net loss attributable to partners
$
(7,422
)
 
$
(14,409
)
 
$
(22,941
)
 
$
(25,235
)
 
 
 
 
 
 
 
 
Earnings per unit and distributions declared
 
 
 
 
 
 
 
Net loss allocated to limited partner common units
$
(3,953
)
 
$
(6,928
)
 
$
(11,782
)
 
$
(11,830
)
Weighted average number of limited partner common units outstanding
33,921
 
26,477
 
31,183
 
25,143
Basic and diluted loss per common unit
$
(0.12
)
 
$
(0.26
)
 
$
(0.38
)
 
$
(0.47
)
 
 
 
 
 
 
 
 
Net loss allocated to limited partner subordinated units
$
(1,423
)
 
$
(3,194
)
 
$
(4,613
)
 
$
(5,744
)
Weighted average number of limited partner subordinated units outstanding
12,214

 
12,214

 
12,214

 
12,214

Basic and diluted loss per subordinated unit
$
(0.12
)
 
$
(0.26
)
 
$
(0.38
)
 
$
(0.47
)
Distributions declared and paid per common unit
$

 
$
0.40

 
$

 
$
0.80

 
See accompanying notes.

5


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited) 
 
Six Months Ended June 30,
 
2016
 
2015
Cash flows from operating activities:
 
 
 
Net loss
$
(22,915
)
 
$
(29,356
)
Adjustments to reconcile net loss to net cash provided by operating activities:

 

Depreciation and amortization
37,449

 
34,603

Unit-based compensation
1,706

 
2,475

Amortization of deferred financing costs and PIK interest
1,904

 
1,727

Loss (gain) on sale of assets, net
(12,576
)
 
180

Unrealized loss (gain) on financial instruments
(55
)
 
221

Equity in losses of joint venture investments
6,963

 
7,155

Distribution from joint venture investment
390

 

Impairment of assets

 
193

Other, net
(184
)
 
(2
)
Changes in operating assets and liabilities:


 


Trade accounts receivable, including affiliates
44,409

 
16,951

Prepaid expenses and other current assets
1,502

 
780

Deposits paid to suppliers
(3,837
)
 

Other non-current assets

 
76

Accounts payable and accrued liabilities
(27,808
)
 
(31,404
)
Other liabilities, including affiliates
3,000

 
904

Net cash provided by operating activities
29,948

 
4,503

Cash flows from investing activities:


 


Capital expenditures
(12,434
)
 
(64,959
)
Insurance proceeds from property damage claims, net of expenditures
125

 
100

Net proceeds from sales of assets
20,402

 
4,693

Consideration paid for Holdings' drop-down acquisition

 
(15,000
)
Investment contributions to joint venture investments
(5,287
)
 
(2,474
)
Net cash provided by (used in) investing activities
2,806

 
(77,640
)
Cash flows from financing activities:


 


Borrowings under our credit facility
3,110

 
102,000

Repayments under our credit facility
(54,250
)
 
(15,000
)
Repayments under our term loan agreement
(2,250
)
 
(2,250
)
Payments on capital lease obligations
(204
)
 
(276
)
Financing costs
(86
)
 
(602
)
Tax withholdings on unit-based compensation vested units
(57
)
 

Payments of distributions and distribution equivalent rights

 
(23,306
)
Expenses paid by Holdings on behalf of Valley Wells' assets

 
17,858

Borrowing of senior unsecured PIK notes
14,000

 

Repayment of senior unsecured PIK notes and PIK interest
(14,260
)
 

Valley Wells operating expense cap adjustment
2,637

 

Contributions from general partner

 
1,281

Common unit issuances to Holdings related to equity cures
11,884

 

Interest on receivable due from Holdings
233

 

Net cash provided by (used in) financing activities
(39,243
)
 
79,705

 
 
 
 
Net increase (decrease) in cash and cash equivalents
(6,489
)
 
6,568

Cash and cash equivalents — Beginning of period
11,348

 
1,649

Cash and cash equivalents — End of period
$
4,859

 
$
8,217


See accompanying notes.

6


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

Partners' Capital
 
 

Limited Partners


 
 

Common

Class B Convertible
 
Subordinated

General Partner
 
Total
BALANCE - December 31, 2015
$
271,236

 
$
300,596

 
$
37,920

 
$
11,584

 
$
621,336

Net loss
(11,768
)
 
(6,081
)
 
(4,607
)
 
(459
)
 
(22,915
)
Unit-based compensation on long-term incentive plan
1,706

 

 

 

 
1,706

Accrued distribution equivalent rights on long-term incentive plan
11

 

 

 

 
11

Tax withholdings on unit-based compensation vested units
(57
)
 

 

 

 
(57
)
Interest on receivable due from Holdings

 

 

 
233

 
233

Common unit issuances to Holdings related to equity cures
12,416

 

 

 
245

 
12,661

Valley Wells' operating expense cap adjustment
2,406

 

 

 

 
2,406

General partner unit in-kind distribution
(15
)
 
(7
)
 
(4
)
 
26

 

Class B Convertible unit in-kind distribution
(945
)
 
1,293

 
(314
)
 
(34
)
 

BALANCE - June 30, 2016
$
274,990

 
$
295,801

 
$
32,995

 
$
11,595

 
$
615,381


7


 
Partners' Capital
 
 
Limited Partners
 
 
 
 
 
 
 
Common
 
Class B Convertible
 
Subordinated
 
General Partner
 
Southcross Holdings' equity in contributed subsidiaries
 
Total
BALANCE - December 31, 2014
$
259,735

 
$
298,833

 
$
48,831

 
$
12,385

 
$
77,320

 
$
697,104

Net loss
(11,802
)
 
(7,100
)
 
(5,694
)
 
(502
)
 
(4,258
)
 
(29,356
)
Contributions from general partner

 

 

 
1,281

 

 
1,281

Class B Convertible unit in-kind distribution
(4,414
)
 
6,706

 
(2,158
)
 
(134
)
 

 

Unit-based compensation on long-term incentive plan
2,333

 

 

 

 

 
2,333

Cash distributions and distribution equivalent rights paid
(19,040
)
 

 
(3,432
)
 
(834
)
 

 
(23,306
)
Accrued distribution equivalent rights on long-term incentive plan
(444
)
 

 

 

 

 
(444
)
General partner unit in-kind distribution
(92
)
 

 
(45
)
 
137

 

 

Valley Wells' operating expense cap adjustment
518

 

 

 

 

 
518

Purchase of assets in Holdings drop-down acquisition
62,640

 

 

 

 
(77,640
)
 
(15,000
)
Contribution of NGL pipelines in Holdings drop-down acquisition

 

 

 

 
15,000

 
15,000

Net assets contributed in Holdings drop-down acquisition in excess of consideration paid
14,806

 
7,929

 
6,387

 
594

 
(29,716
)
 

Expenses paid by Holdings on behalf of Valley Wells' assets

 

 

 

 
17,858

 
17,858

Net liabilities assumed by Holdings in Holdings drop-down acquisition

 

 

 

 
1,436

 
1,436

BALANCE - June 30, 2015
$
304,240

 
$
306,368

 
$
43,889

 
$
12,927

 
$

 
$
667,424



See accompanying notes.

8


SOUTHCROSS ENERGY PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
 
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
 
Organization
 
Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") is a Delaware limited partnership formed in April 2012. Our common units are listed on the New York Stock Exchange under the symbol “SXE.” We are a master limited partnership, headquartered in Dallas, Texas, that provides natural gas gathering, processing, treating, compression and transportation services and NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our assets are located in South Texas, Mississippi and Alabama and include four gas processing plants, two fractionation facilities and our pipelines.

Southcross Holdings LP, a Delaware limited partnership (“Holdings”), indirectly owns 100% of Southcross Energy Partners GP, LLC, a Delaware limited liability company, our General Partner (“General Partner”) (and therefore controls us), all of our subordinated and Class B convertible units and 40.7% of our common units. Our General Partner owns an approximate 2.0% interest in us and all of our incentive distribution rights.

Following the emergence of Holdings from its Chapter 11 reorganization proceeding on April 13, 2016 (as discussed below), EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings, and a group of consolidated lenders under Holdings' term loan (the “Lenders”) own the remaining one-third equity interest.

Holdings Chapter 11 Reorganization

On March 28, 2016, Holdings and certain of its subsidiaries (excluding us, our General Partner and our subsidiaries) filed a pre-packaged plan of reorganization (the “POR”) under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of Texas to restructure its debt obligations and strengthen its balance sheet. Our operations, customers, suppliers, partners and other constituents were excluded from such proceeding. On April 11, 2016, the bankruptcy court confirmed Holdings’ POR, and on April 13, 2016, Holdings and its subsidiaries emerged from its bankruptcy with the Lenders being issued 33.34% of the limited partner interests in Holdings in exchange for the elimination of certain funded debt obligations. EIG and Tailwater each contributed $85 million in cash (or $170 million in the aggregate) in exchange for each Sponsor receiving 33.33% of the limited partner interests in Holdings. In addition, Holdings committed to provide us $50 million (as part of the Equity Cure Agreement defined below), out of the $170 million in new equity contributed to Holdings from the Sponsors, to provide us with sufficient liquidity to comply with the applicable financial covenants set forth in our credit agreement. We believe Holdings’ reorganization and POR will enhance our liquidity position, strengthen our balance sheet and position Holdings to continue to support our business and growth.

Liquidity Consideration
Energy commodity prices declined substantially in 2014 due to a number of factors, including a continuing growth of supply, slowdown or decline in demand and challenges in global economic, financial and monetary markets. The continued, sustained low natural gas, NGL and crude oil prices have negatively impacted natural gas and oil exploration and production activity levels industry-wide. Our future cash flow will be materially adversely affected if this prolonged pricing deterioration continues for the commodities we sell or if the reduction in drilling for oil or natural gas continues in the geographic areas in which we operate continues, including the Eagle Ford Shale region.
The majority of our revenue is derived from fixed-fee contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than being paid based on the value of the underlying natural gas or NGLs. In addition, a portion of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity.
After considering these uncertainties, our forecast indicates future shortfalls in the amount of consolidated EBITDA (as defined in the Third Amended and Restated Revolving Credit Agreement with Wells Fargo, N.A., UBS Securities LLC and Barclays Bank PLC and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”), as amended in May 2015) necessary to remain in compliance with the consolidated total leverage ratio of our Financial Covenants (as defined in Note 6) in our Credit Facility (as defined in Note 6) for the remainder of 2016. As discussed in further detail in Note 6, we have the

9


right to cure such a Financial Covenant Default (as defined in Note 6) by either our Sponsors or Holdings purchasing equity interests in or making capital contributions (an equity cure) resulting in, among other things, proceeds that, if added to consolidated EBITDA, would result in us satisfying the Financial Covenants. Once such an equity cure is made, it is included in our consolidated EBITDA calculation in any rolling twelve month period that includes the quarter that was cured. Should there be an event of default under the Credit Facility, and such default is not cured, we also would experience a cross default under our Term Loan Agreement (defined in Note 6) and all of our debt would become due and payable to our lenders.
On March 17, 2016, we entered into an equity cure contribution agreement (the “Equity Cure Agreement”) with Holdings whereby we have the right to cure any default with respect to our Financial Covenants by having Holdings purchase equity interests in or make capital contributions to us, in an aggregate amount of up to $50 million. The fair value of the Equity Cure Agreement was not material at inception. In connection with Holdings' Chapter 11 reorganization, and pursuant to the terms of the Equity Cure Agreement, Holdings has committed to contribute up to $50 million to us (the “Contribution Amount”) to ensure we have sufficient liquidity to comply with applicable Financial Covenants through the quarter ended December 31, 2016. In exchange for the Contribution Amount, we will issue Holdings a number of our common units representing limited partner interests equal to, subject to certain exceptions, (i) the applicable Contribution Amount divided by (ii) a common unit reference price (“Reference Price”) equal to the volume weighted daily average price of the common units on the New York Stock Exchange (“VWAP”) calculated for a period of 15 trading days ending two trading days prior to the contribution by Holdings.
As of June 30, 2016, we were in compliance with the consolidated total leverage ratio of our Financial Covenants. However, we used an aggregate $12.4 million of the $50 million equity commitment from Holdings to fund equity cures as of December 31, 2015 and March 31, 2016. In accordance with the requirements above and the amounts funded for these equity cures, Holdings was issued 8,029,729 common units on May 2, 2016 for the fourth quarter 2015 equity cure ($11.9 million) that was funded in March 2016 and 359,459 common units on May 13, 2016 for the first quarter 2016 equity cure ($0.5 million) that was funded in July 2016. We anticipate funding additional equity cures needed to maintain compliance with our Financial Covenants through the end of 2016 with the equity commitment from Holdings or other equity contributions from Holdings. Therefore, these financial statements have been presented as if we will continue as a going concern. See Note 6.
On January 7, 2016, in response to our need for additional liquidity, we issued at par senior unsecured PIK notes in the aggregate principal amount of $14.0 million (the "PIK Notes") to affiliates of EIG and Tailwater, with interest at a rate of 7% due January 7, 2017. Contemporaneous with the resolution of Holdings’ bankruptcy proceedings in April 2016, the PIK Notes and the related PIK interest of $0.3 million were repaid in full.
Distribution Suspension
The board of directors of our General Partner voted not to pay a quarterly distribution with respect to the fourth quarter of 2015 and the first and second quarters of 2016 and instead, based on current conditions, to reserve any excess cash for the operation of our business. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders. The board of directors and management will continue to evaluate the Partnership's ability to reinstate the distribution in future periods. See Note 3.
Segments
Our chief operating decision-maker is our General Partner’s Chief Executive Officer, who reviews financial information presented on a consolidated basis in order to assess our performance and make decisions about resource allocations. There are no segment managers who are held accountable by the chief operating decision-maker, or anyone else, for operations, operating results and planning for levels or components below the consolidated unit level. Accordingly, we have determined that we have one reportable segment.
 
Basis of Presentation
 
We prepared this report under the rules and regulations of the Securities and Exchange Commission (the “SEC”) and in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements. Accordingly, these condensed consolidated financial statements do not include all of the disclosures required by GAAP and should be read in conjunction with our 2015 Annual Report on Form 10-K (“2015 Annual Report on Form 10-K”). The condensed consolidated financial statements as of June 30, 2016 and December 31, 2015, and for the three and six months ended June 30, 2016 and 2015, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2015 Annual Report on Form 10-K. Adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations and financial position have been included herein. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements.


10


We recognized the 2015 Holdings Acquisition (defined in Note 2) at Holdings’ historical cost because the acquisition was executed by entities under common control. Thus, the difference between consideration paid and Holdings’ historical cost (net book value) at May 7, 2015, the date on which the 2015 Holdings Acquisition closed, was recorded as an increase to partners’ capital. Due to the common control aspect, the 2015 Holdings Acquisition was accounted for by the Partnership on an “as if pooled” basis for the periods during which common control existed which began on August 4, 2014. See Note 2.
 
The accompanying unaudited condensed consolidated financial statements were prepared in conformity with GAAP, which requires management to make various estimates and assumptions that may affect the amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from those estimates. Information for interim periods may not be indicative of our operating results for the entire year.
 
The disclosures included in this report provide an update to our 2015 Annual Report on Form 10-K.
 
We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed in this report.

Significant Accounting Policies
 
During the second quarter of 2016, there were no material changes to our significant accounting policies described in Note 1 of our 2015 Annual Report on Form 10-K.

Recent Accounting Pronouncements 
Accounting standard-setting organizations frequently issue new or revised accounting pronouncements. We review and evaluate new pronouncements and existing pronouncements below to determine their impact, if any, on our consolidated financial statements. We are evaluating the impact of each pronouncement on our consolidated financial statements.
In February 2015, the Financial Accounting Standards Board (“FASB”) issued a pronouncement that amended the current consolidation guidance with regard to variable interest entities and voting interest entities. The standard became effective in 2016 and amends the guidance and framework for determining whether a partial-interest owner in a subsidiary should consolidate and potentially revise their disclosures regarding the topic. We adopted this standard in 2016.

In February 2016, the FASB issued a pronouncement amending disclosure and presentation requirements for lessees and lessors to reflect more accurately the recognition of assets and liabilities that arise from leases. The pronouncement states that a lessee should recognize a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term on the face of the balance sheet. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. This standard will become effective beginning in 2019.

In March 2016, the FASB issued a pronouncement amending the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. This standard will become effective beginning in 2017.

In March 2016, the FASB issued a pronouncement amending the requirement to adopt retroactively the equity method of accounting. The pronouncement eliminates the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The new guidance requires that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. Therefore, upon qualifying for the equity method of accounting, no retroactive adjustment of the investment is required. In addition, the pronouncement requires that an entity that has an available-for sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive

11


income at the date the investment becomes qualified for use of the equity method. This standard will become effective beginning in 2017.

In 2014, a comprehensive new revenue recognition standard that will supersede substantially all existing revenue recognition guidance under GAAP was issued. The standard's core principle is that a company will recognize revenue when it transfers promised goods or services to customers and in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In April 2016, the FASB issued an accounting pronouncement which updates the identifying performance obligations and licensing implementation guidance. The standard will become effective beginning in 2018.
In May 2016, the FASB issued a pronouncement for the new revenue recognition guidance on assessing collectability, presentation of sales taxes, non-cash consideration, completed contracts and contract modifications. The pronouncement is intended to reduce the potential for diversity in practice at initial application and cost and complexity on an ongoing basis. The standard will become effective beginning in 2018.
2. ACQUISITIONS

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

The 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the financial results of the Valley Wells System and Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction, and before May 7, 2015. The acquired NGL pipelines were accounted for as an asset acquisition and were included in the historical financial statements beginning on May 7, 2015. As a carve-out transaction, the 2015 Holdings Acquisition had no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of Holdings as of December 31, 2014. Given their nature and the fact that carve-out financial statements are meant to represent an entity’s operations as if it had existed as of the time common control occurred, we have presented these amounts as third-party receivables and payables.
The amount of the consideration paid below Holdings’ net book value of the assets received and liabilities assumed of the 2015 Holdings Acquisition was recorded as an increase to partners’ capital as summarized as follows (in thousands):
Consideration paid(1)
$
77,640

Total net assets contributed
107,356

Net assets contributed in excess of consideration paid
$
29,716

Allocation of increase to partners' capital:

Common limited partner interest
$
14,806

Class B Convertible limited partner interest
7,929

Subordinated limited partner interest
6,387

General Partner interest
594

Total increase to partners' capital
$
29,716

 
(1) This amount was calculated as follows: $15.0 million of cash plus 4.5 million new common units at an issue price of $13.92, the closing price of the Partnership’s common units on May 7, 2015.
Supplemental Disclosures - As If Pooled Basis. As noted above, the 2015 Holdings Acquisition was between commonly controlled entities which required that we account for the acquisitions in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and the Valley Wells System and Compression Assets have been combined to reflect the historical operations, financial position and cash flows from the date common control began on August 4, 2014.

12


Revenues and net income for the previously separate entities and the combined amounts for the three and six months ended June 30, 2015, are as follows (in thousands):
 
Three Months Ended June 30, 2015
 
Six Months Ended June 30, 2015
Partnership revenues
$
165,560

 
$
346,109

Valley Wells System and Compression Assets revenue
1,660

 
7,049

Combined revenues
$
167,220

 
$
353,158

 


 


Partnership net loss
$
(14,348
)
 
$
(25,098
)
Valley Wells System and Compression Assets net loss
(1,103
)
 
(4,258
)
Combined net loss
$
(15,451
)
 
$
(29,356
)


3. NET LOSS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS
 
Net Loss Per Limited Partner Unit
 
The following is a reconciliation of net loss attributable to limited partners and the limited partner units used in the basic and diluted earnings per unit calculations for the three and six months ended June 30, 2016 and 2015 (in thousands, except unit and per unit data): 
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2016
 
2015
 
2016
 
2015
Net loss
 
$
(7,396
)
 
$
(15,451
)
 
$
(22,915
)
 
$
(29,356
)
General partner unit in-kind distribution
 
(26
)
 
(61
)
 
(26
)
 
(137
)
Net loss attributable to Holdings
 

 
(1,103
)
 

 
(4,258
)
Net loss attributable to partners
 
$
(7,422
)
 
$
(14,409
)
 
$
(22,941
)
 
$
(25,235
)
 
 
 
 
 
 
 
 
 
General partner's interest (1)
 
$
(156
)
 
$
(306
)
 
$
(465
)
 
$
(561
)
Class B Convertible limited partner interest (1)
 
(1,890
)
 
(3,981
)
 
(6,081
)
 
(7,100
)
Limited partners' interest (1)
 
 
 
 
 
 
 
 
    Common
 
$
(3,953
)
 
$
(6,928
)
 
$
(11,782
)
 
$
(11,830
)
    Subordinated
 
(1,423
)
 
(3,194
)
 
(4,613
)
 
(5,744
)

(1) General Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the General Partner unit in-kind distributions. The Class B convertible unit (“Class B Convertible Units”) interest is calculated based on the allocation of only net losses for the period.
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Common Units
 
2016
 
2015
 
2016
 
2015
Interest in net loss
 
$
(3,953
)
 
$
(6,928
)
 
$
(11,782
)
 
$
(11,830
)
Effect of dilutive units - numerator (1)
 

 

 

 

    Dilutive interest in net loss
 
$
(3,953
)
 
$
(6,928
)
 
$
(11,782
)
 
$
(11,830
)
 
 
 
 
 
 
 
 
 
Weighted-average units - basic
 
33,920,732

 
26,476,520

 
31,183,306

 
25,143,455

Effect of dilutive units - denominator (1)
 

 

 

 

    Weighted-average units - dilutive
 
33,920,732

 
26,476,520

 
31,183,306

 
25,143,455

 
 
 
 
 
 
 
 
 
Basic and diluted net loss per common unit
 
$
(0.12
)
 
$
(0.26
)
 
$
(0.38
)
 
$
(0.47
)


13


 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Subordinated Units
 
2016
 
2015
 
2016
 
2015
Interest in net loss
 
$
(1,423
)
 
$
(3,194
)
 
$
(4,613
)
 
$
(5,744
)
Effect of dilutive units - numerator (1)
 

 

 

 

    Dilutive interest in net loss
 
$
(1,423
)
 
$
(3,194
)
 
$
(4,613
)
 
$
(5,744
)
 
 
 
 
 
 
 
 
 
Weighted-average units - basic
 
12,213,713

 
12,213,713

 
12,213,713

 
12,213,713

Effect of dilutive units - denominator (1)
 

 

 

 

    Weighted-average units - dilutive
 
12,213,713

 
12,213,713

 
12,213,713

 
12,213,713

 
 
 
 
 
 
 
 
 
Basic and diluted net loss per subordinated unit
 
$
(0.12
)
 
$
(0.26
)
 
$
(0.38
)
 
$
(0.47
)

(1) Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts was 55,202 and 7,074 for the three and six months ended June 30, 2016, respectively.
 
Our calculation of the number of weighted-average units outstanding includes the common units that have been awarded to our directors that are deferred under our Non-Employee Director Deferred Compensation Plan.

Distributions
 
Our agreement of limited partnership (as amended and restated, the “Partnership Agreement”), requires that within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our General Partner. There is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Beginning with the third quarter of 2014, until such time that we have a distributable cash flow divided by cash distributions ratio (“Distributable Cash Flow Ratio”) of at least 1.0, Holdings, the indirect holder of all of our subordinated units, waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0. In addition, the Credit Agreement Amendment (as defined in Note 6) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units. See Note 6.
 
Cash Distributions

The board of directors of our General Partner voted not to pay a quarterly distribution with respect to the fourth quarter of 2015 and the first and second quarters of 2016 and instead, based on current conditions, to reserve any excess cash for the operation of our business. The board of directors of our General Partner and our management believe this suspension to be in the best interest of our unitholders. The board of directors and management will continue to evaluate the Partnership's ability to reinstate the distribution in future periods. See Note 1.

Holdings did not receive a distribution for the first quarter of 2015 in respect of the 4.5 million common units acquired by it in connection with the 2015 Holdings Acquisition.
Paid In-Kind Distributions

Class B Convertible Units. As of June 30, 2016, the Class B Convertible Units consisted of 16,522,484 of such units including the additional Class B Convertible Units issued in-kind as a distribution (“Class B PIK Units”). The Class B Convertible Units are not participating securities for purposes of the earnings per unit calculation. Commencing with the quarter ended September 30, 2014 and until converted, as long as certain requirements are met, the holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit. These distributions will be paid quarterly in Class B PIK Units within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of the Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions. See Note 8.


14


The following table presents the PIK distributions issued on the Class B Convertible Units during 2016 (in thousands, except per unit and in-kind distribution units):
Payment Date
 
Attributable to the Quarter Ended
 
Per Unit Distribution
 
In-Kind Class B Convertible Unit
Distributions to Class B Convertible Holders
 
In-Kind 
Class B Convertible Distributions
Value
(1)
 
In-Kind 
Unit
Distribution
to General 
Partner
 
In-Kind General Partner Distribution Value(1)
2016
 
 
 
 
 
 
 
 
 
 
 
 
August 9, 2016
 
June 30, 2016
 
$
0.3257

 
289,165

 
$
581

 
5,901

 
$
12

May 9, 2016
 
(2)
 
0.3257

 
563,494

 
1,293

 
11,499

 
26

 
(1) The fair value was calculated as required, based on the common unit price at the quarter end date for the period attributable to the distribution, multiplied by the number of units distributed.
(2) We suspended distributions to holders of our Class B Convertible Units for the quarters ended December 31, 2015 and March 31, 2016. However, under the terms of our Partnership agreement, such paid in-kind (“PIK”) distributions continued to accumulate. On May 9, 2016, we issued the accumulated Class B Convertible Units to Holdings and general partner units to our General Partner related to the quarters ended December 31, 2015 and March 31, 2016.

4. FINANCIAL INSTRUMENTS

Fair Value Measurements

We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:
Level 1—Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes our cash and cash equivalents, accounts receivable and accounts payable.
Level 2—Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes variable rate debt, over-the-counter swap contracts based upon natural gas price indices and interest rate derivative transactions.
Level 3—Represents derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources. We do not have financial assets and liabilities classified as Level 3.

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

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


15


Derivative Financial Instruments
Interest Rate Derivative Transactions
We enter into interest rate swap contracts whereby we receive a floating rate and pay a fixed rate to reduce the risk associated with the variability of interest rates for our term loan borrowings. Our interest rate swap position was as follows (in thousands):
 
 
 
 
 
 
 
 
Estimated Fair Value
Notional Amount
 
Fixed Rate
 
Effective Date
 
Maturity Date
 
June 30, 2016
$
100,000

 
1.195
%
 
June 30, 2015
 
January 1, 2017
 
$
(104
)

Effectively, we enter into interest rate cap contracts to limit our London Interbank Offered Rate (“LIBOR”)-based interest rate risk on the portion of debt hedged at the contracted cap rate. Our interest rate cap position was as follows (in thousands):
 
 
 
 
 
 
 
 
Estimated Fair Value
Notional Amount
 
Cap Rate
 
Effective Date
 
Maturity Date
 
June 30, 2016
$
20,000

 
1.500
%
 
December 31, 2014
 
December 31, 2016
 
$

80,000

 
3.000
%
 
June 30, 2015
 
June 30, 2017
 

50,000

 
3.000
%
 
December 31, 2015
 
December 31, 2017
 

50,000

 
3.000
%
 
June 30, 2016
 
June 30, 2018
 
1

 
 
 
 
 
 
 
 
$
1


In June 2016, we entered into an interest rate cap contract for $50.0 million notional value, effective June 30, 2016, with a maturity date of June 30, 2018. The contract effectively caps our LIBOR-based interest rate on that portion of debt at 3.0%.

These interest rate derivatives are not designated as cash flow hedging instruments for accounting purposes and as a result, changes in the fair value are recognized in interest expense immediately.

The fair value of our interest rate derivative transactions is determined based on a discounted cash flow method using contractual terms of the transactions. The floating coupon rate is based on observable rates consistent with the frequency of the interest cash flows. We have elected to present our interest rate derivatives net in the balance sheets. There was no effect of offsetting in the balance sheets as of June 30, 2016 or December 31, 2015.

The fair values of our interest rate derivative transactions were as follows (in thousands):
 
Significant Other Observable Inputs (Level 2)
 
Fair Value Measurement as of
 
June 30, 2016
 
December 31, 2015
Current interest rate derivative assets
$

 
$
6

Non-current interest rate derivative assets

 
4

Current interest rate derivative (liabilities)
(104
)
 
(169
)
Total interest rate derivatives
$
(104
)
 
$
(159
)

The realized and unrealized amounts recognized in interest expense associated with derivatives were as follows (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,

2016
 
2015
 
2016
 
2015
Unrealized loss (gain) on interest rate derivatives
$
(85
)
 
$
54

 
$
(55
)
 
$
109

Realized loss on interest rate derivatives
99

 
154

 
198

 
258


Commodity Swaps
 
In our normal course of business, periodically we enter into month-ahead swap contracts to hedge our exposure to certain intra-month natural gas index pricing risk. We had no outstanding month-ahead swap contracts as of June 30, 2016 and December 31, 2015. 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.

16


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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Realized gain on commodity swap derivatives
$

 
$
125

 
$

 
$
136

Unrealized loss on commodity swap derivatives

 

 

 
(112
)
5. LONG-LIVED ASSETS
Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
 
Estimated
Useful Life (yrs)
 
June 30, 2016
 
December 31, 2015
Pipelines
15-30
 
$
552,197

 
$
542,790

Gas processing, treating and other plants
15
 
556,917

 
547,253

Compressors
7-15
 
76,661

 
72,750

Rights of way and easements
15
 
50,160

 
46,692

Furniture, fixtures and equipment
5
 
9,320

 
9,252

Capital lease vehicles
3-5
 
2,442

 
2,442

    Total property, plant and equipment
 
 
1,247,697

 
1,221,179

Accumulated depreciation and amortization
 
 
(249,944
)
 
(212,991
)
    Total
 
 
997,753

 
1,008,188

 
 
 
 
 
 
Construction in progress
 
 
12,798

 
32,214

Land and other
 
 
23,715

 
25,599

    Property, plant and equipment, net
 
 
$
1,034,266

 
$
1,066,001

 
Depreciation is provided using the straight-line method based on the estimated useful life of each asset.

In May 2016, we finalized the sale of a portion of pipeline for $15.0 million, which was determined to be a sale of assets. We recorded a $13.6 million gain on sale of assets on our condensed consolidated statement of operations in connection with this sale.
   
Intangible Assets

Intangible assets of $1.4 million and $1.5 million as of June 30, 2016 and December 31, 2015, respectively, represent the unamortized value assigned to long-term supply and gathering contracts. These intangible assets are amortized on a straight-line basis over the 30-year expected useful lives of the contracts through 2041. Amortization expense over the next five years related to intangible assets is not significant.


17


6. LONG-TERM DEBT 

Our outstanding debt and related information at June 30, 2016 and December 31, 2015 are as follows (in thousands):

June 30, 2016
 
December 31, 2015
Revolving credit facility due 2019
$
130,555

 
$
181,695

Term loans (including original issue discount of $1.6 million and $1.8 million as of June 30, 2016 and December 31, 2015, respectively) due 2021
439,378

 
441,464

Total long-term debt (including current portion)
569,933

 
623,159

Current portion of long-term debt
(4,500
)
 
(4,500
)
Deferred financing costs
(12,748
)
 
(14,141
)
Total long-term debt
$
552,685

 
$
604,518




 


Outstanding letters of credit
$
16,378

 
$
18,305

Remaining unused borrowings
$
53,067

 
$

 
Three Months Ended June 30,
 
Six Months Ended June 30,

2016

2015

2016

2015
Weighted average interest rate
5.24
%
 
5.15
%
 
5.23
%
 
5.13
%
Average outstanding borrowings
$
608,382

 
$
276,441

 
$
617,368

 
$
265,537

Maximum borrowings
$
626,680

 
$
563,625

 
$
628,055

 
$
563,625


Senior Credit Facilities

Our long-term debt arrangements consist of (a) the Third A&R Revolving Credit Agreement (as defined in Note 1) and (b) a Term Loan Credit Agreement with Wilmington Trust, National Association, UBS Securities LLC and Barclays Bank PLC and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest of the facilities ranking pari passu.

Third A&R Revolving Credit Agreement

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

(a)
the letters of credit sublimit is $75 million; and

(b)
if we fail to comply with the consolidated total leverage ratio, consolidated senior secured leverage ratio and the consolidated interest coverage ratio covenants (the “Financial Covenants”) (a “Financial Covenant Default”), we have the right (a limited number of times) to cure such Financial Covenant Default by having the Sponsors purchase equity interests in or make capital contributions to us resulting in, among other things, proceeds that, if added to consolidated EBITDA, as defined in the Third A&R Revolving Credit Agreement, would result in us satisfying the Financial Covenants.

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

The Credit Agreement Amendment, among other things:

(a) (i) revised the maximum consolidated total leverage ratio set at 5.5 to 1.0 as of the last day of the fiscal quarter ending each of December 31, 2015, March 31, 2016 and June 30, 2016, (ii) 5.25 to 1.0 as of the last day of the fiscal quarter ending September 30, 2016, and (iv) 5.00 to 1.0 as of the last day of each fiscal quarter thereafter, in each case, without any step-ups in connection with acquisitions;


18


(b) increased the applicable margins used in connection with the loans and the commitment fee so that the applicable margin for Eurodollar Loans (as used in the Third A&R Revolving Credit Agreement) ranges from 2.00% to 4.50%, the applicable margin for base rate loans ranges from 1.00% to 3.50% and the applicable rate for commitment fees ranges from 0.375% to 0.500%; and

(c) allows us an unlimited number of quarterly equity cures related to our Financial Covenant Default through the fourth quarter of 2016, and no more than two in a twelve month period thereafter for the life of the agreement.

Term Loan Agreement

The Term Loan Agreement is a seven-year $450 million senior secured term loan facility. Borrowings under our Term Loan Agreement bear interest at LIBOR plus 4.25% or a base rate as defined in the respective credit agreement with a LIBOR floor of 1.00%. The facility is amortized in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of the initial loan ($1.125 million), with the remainder due on the maturity date.

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 long-term debt on the balance sheets. Changes in deferred financing costs are as follows (in thousands):
 
2016
 
2015
Deferred financing costs, January 1
$
14,141

 
$
16,602

Capitalization of deferred financing costs
130

 
597

Less:

 

Amortization of deferred financing costs
(1,523
)
 
(1,557
)
Deferred financing costs, June 30
$
12,748

 
$
15,642


7. COMMITMENTS AND CONTINGENCIES
 
Legal Matters
 
From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. For example, during periods when we are expanding our operations through the development of new pipelines or the construction of new plants, we may become involved in disputes with landowners that are in close proximity to our activities. While we are currently involved in several such proceedings and disputes, our management believes that none of such proceedings or disputes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims ultimately will have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

Formosa. In March 2013, one of our subsidiaries, Southcross Marketing Company Ltd. (“Marketing”), filed suit against Formosa Hydrocarbons Company, Inc. (“Formosa”) for breach of contract under a gas processing and sales contract between the parties. Formosa filed a counterclaim against Marketing for breach of such contract and a related agreement between the parties. After a bench trial held in January 2015, the judge ruled that Formosa had breached certain of its obligations under the gas processing and sales contract and that Marketing had breached certain of its obligations under such contract and the related agreement. On June 27, 2016, a final judgment was entered in which we were awarded for damages, attorneys’ fees and interest. Both parties filed a request for findings of fact and conclusions of law on July 15, 2016. On July 27, 2016, Marketing filed a notice of appeal seeking to appeal certain of the rulings set forth in the final judgment while, concurrently, Formosa filed a motion to modify the final judgment with respect to certain of the rulings in the final judgment and, alternatively, a motion for new trial. The payment of any award will be deferred until the resolution of Marketing’s notice of appeal and Formosa’s motions.
 

19


Regulatory Compliance
 
In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition. 

Leases

Capital Leases
 
We have auto leases that are classified as capital leases. The termination dates of the lease agreements vary from 2016 to 2019. We recorded amortization expense related to the capital leases of $0.1 million and $0.2 million for the three and six months ended June 30, 2016 and $0.1 million and $0.3 million for the three and six months ended June 30, 2015. Capital leases entered into during the three and six months ended June 30, 2016 were $0.2 million and $0.2 million, respectively. Capital leases entered into during the three and six months ended June 30, 2015 were $0.2 million and $0.4 million, respectively. The capital lease obligation amounts included on the balance sheets were as follows (in thousands):
 
June 30, 2016
 
December 31, 2015
Other current liabilities
$
376

 
$
362

Other non-current liabilities
304

 
522

Total
$
680

 
$
884


Operating Leases
 
We maintain operating leases in the ordinary course of our business activities. These leases include those for office and other operating facilities and equipment. The termination dates of the lease agreements vary from 2016 to 2025. Expenses associated with operating leases, recorded in operations and maintenance expenses and general and administrative expenses in our statements of operations, were $1.8 million and $2.7 million for the three and six months ended June 30, 2016, respectively, and $0.6 million and $1.7 million for the three and six months ended June 30, 2015, respectively. A rental reimbursement included in our lease agreement associated with the office space we leased in June 2015 of $2.1 million, net of amortization, has been recorded as a deferred liability on our condensed consolidated balance sheets as of June 30, 2016. This amount will continue to be amortized against the lease payments over the length of the lease term.

Purchase Commitments
 
At June 30, 2016, we had commitments of $7.4 million related primarily to the purchase of pipelines and compressors for our various capital expansion projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
 

20


8. PARTNERS’ CAPITAL
 
Ownership

Our units outstanding as of June 30, 2016 are as follows (in units):
 
 
Partners’ Capital
 
 
 
 
Owned by Parent
 
 
Public
 
Holdings
 
Class B
 
 
 
General
 
 
Common
 
Common
 
Convertible
 
Subordinated
 
Partner
Units outstanding as of December 31, 2015
 
21,804,219

 
6,616,400

 
15,958,990

 
12,213,713

 
1,154,965

Vesting of LTIP units, net
 
92,685

 

 

 

 

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

 

 
563,494

 

 
184,600

Common unit issuances to Holdings related to equity cures
 

 
8,389,188

 

 

 

Units outstanding as of June 30, 2016
 
21,896,904

 
15,005,588

 
16,522,484

 
12,213,713

 
1,339,565


Common Units
Our common units represent limited partner interests in us. The holders of our common units are entitled to participate in our distributions and are entitled to exercise the rights and privileges available to limited partners under our Partnership Agreement. In accordance with the requirements of the Equity Cure Agreement, Holdings was issued 8,029,729 common units on May 2, 2016 and 359,459 common units on May 13, 2016.
Class B Convertible Units
The Class B Convertible Units consist of 14,633,000 units plus any additional Class B PIK Units. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions as noted below.

Our Partnership Agreement does not allow additional Class B Convertible Units (other than Class B PIK Units) to be issued without the prior approval of our General Partner and the holders of a majority of the outstanding Class B Convertible Units. As of June 30, 2016, all of our outstanding Class B Convertible Units were indirectly owned by Holdings.

Distribution Rights: The holders of the Class B Convertible Units will receive quarterly distributions in an amount equal to $0.3257 per unit paid in Class B PIK Units (based on a unit issuance price of $18.61) within 45 days after the end of each quarter until converted and as long as certain requirements are met. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us.

We suspended distributions to holders of our Class B Convertible Units for the quarters ended December 31, 2015 and March 31, 2016. However, under the terms of our Partnership agreement, such paid in-kind (“PIK”) distributions continued to accumulate. On May 9, 2016, we issued the accumulated 563,494 Class B Convertible Units to Holdings and 11,499 general partner units to our General Partner related to the quarters ended December 31, 2015 and March 31, 2016.

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

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


21


Subordinated Units
 
Subordinated units represent limited partner interests in us and convert to common units at the end of the Subordination Period (as defined in our Partnership Agreement). The principal difference between our common units and our subordinated units is that in any quarter during the Subordination Period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units do not accrue arrearages. Beginning with the third quarter of 2014, until such time we have a Distributable Cash Flow Ratio of at least 1.0, Holdings, the indirect holder of the subordinated units has waived the right to receive distributions on any subordinated units that would cause the Distributable Cash Flow Ratio to be less than 1.0. In addition, the Credit Agreement Amendment imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units. See Note 6.

General Partner Interests
 
As defined by our Partnership Agreement, general partner units are not considered to be units (common or subordinated), but are representative of our general partner’s 2.0% ownership interest in us. Our General Partner has received general partner unit PIK distributions in connection with the Class B Convertible Units. In connection with other equity issuances, our General Partner has made capital contributions in exchange for additional general partner units to maintain its 2.0% ownership interest in us. In connection with the 8,029,729 common units issued to Holdings on May 2, 2016 and the 359,459 common units issued to Holdings on May 13, 2016, we recorded a receivable from our General Partner on our condensed consolidated balance sheets in exchange for 171,209 general partner units to maintain its 2.0% ownership interest in us.

9. TRANSACTIONS WITH RELATED PARTIES
 
Affiliated Directors
 
Effective April 13, 2016, the board of directors of our General Partner includes one director affiliated with EIG, one director affiliated with Tailwater and four outside directors. Pursuant to the terms of the POR, the Lenders have the right to appoint two additional directors (one of which must be independent). The eighth member of the board of directors of our General Partner, and its chairman, is David W. Biegler. Mr. Biegler will serve as chairman until the earlier of August 4, 2016, his death or resignation. Our non-employee directors are reimbursed for certain expenses incurred for their services to us. The director services fees and expenses are included in general and administrative expenses in our statements of operations. We incurred fees and expenses related to the services from our affiliated directors as follows (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Charlesbank Capital Partners, LLC(1)
$
30

 
$
42

 
$
94

 
$
80

EIG
16

 
17

 
45

 
33

Tailwater
18

 
17

 
44

 
33

Total fees and expenses paid for director services to affiliated entities
$
64

 
$
76

 
$
183

 
$
146


(1) Charlesbank Capital Partners, LLC indirectly owned approximately one-third of Holdings until April 13, 2016. See Note 1.
    

22


Southcross Energy Partners GP, LLC (our General Partner)
 
Our General Partner does not receive a management fee or other compensation for its management of us. However, our General Partner and its affiliates are entitled to reimbursements for all expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. We incurred expenses related to these reimbursements as follows (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Reimbursements included in general and administrative expenses
$
3,538

 
$
3,845

 
$
7,034

 
$
7,080

Reimbursements included in operations and maintenance expenses
5,548

 
5,133

 
10,846

 
10,432

Total reimbursements to our General Partner and its affiliates
$
9,086

 
$
8,978

 
$
17,880

 
$
17,512


Compensation expense for services incurred by us on behalf of Southcross Energy LLC was billed to Southcross Energy LLC for the three and six months ended June 30, 2015. Compensation expense not incurred on our behalf of $0.2 million and $0.4 million for the three and six months ended June 30, 2015, respectively, was billed to Southcross Energy LLC.

Other Transactions with Affiliates

On March 17, 2016, our General Partner entered into retention agreements with certain executives of our General Partner, pursuant to which the executives received a one-time special restructuring bonus in an amount equal to 100% of then-current annual salary for remaining employed with our General Partner through the date of Holdings’ emergence from bankruptcy. The bonuses of $1.5 million were paid on April 22, 2016 and were allocated 100% to Holdings.

In addition, each of these executives of our General Partner will receive a one-time retention bonus in an amount equal to 100% of then-current annual salary if the executive remains continuously employed with our General Partner through November 1, 2016. We have recorded $0.3 million and $0.6 million in general and administrative expenses for our allocable share of costs for the three and six months ended June 30, 2016.

On January 7, 2016, in response to our need for additional liquidity, we issued at par senior unsecured PIK notes in the
aggregate principal amount of $14.0 million (the "PIK Notes") to affiliates of EIG and Tailwater, with interest at a rate of
7% due January 7, 2017. Contemporaneous with the resolution of Holdings’ bankruptcy proceedings in April 2016, the PIK Notes and the related PIK interest of $0.3 million were repaid in full.

We have a gas gathering and processing agreement (the “G&P Agreement”) and an NGL sales agreement (the “NGL Agreement”) with an affiliate of Holdings. Under the terms of these commercial agreements, we transport, process and sell rich natural gas for the affiliate of Holdings in return for agreed-upon fixed fees, and we can sell natural gas liquids that we own to Holdings at agreed-upon fixed prices. The NGL Agreement also permits us to utilize Holdings’ fractionation services at market-based rates.

In conjunction with the 2015 Holdings Acquisition, we entered into a series of commercial agreements with affiliates of Holdings including a gas gathering and treating agreement, a compression services agreement, a repair and maintenance agreement and an NGL transportation agreement. Under the terms of these commercial agreements, we gather, treat, transport, compress and redeliver natural gas for the affiliates of Holdings in return for agreed-upon fixed fees. In addition, under the NGL transportation agreement, we transport a minimum volume of NGLs per day at a fixed rate per gallon. The operational expense associated with such agreements has been capped at $1.7 million per quarter. In the first and second quarter of 2016, we exceeded this cap by $1.0 million and $1.4 million, respectively. As of June 30, 2016, accounts receivable - affiliates in our condensed consolidated balance sheets included $1.4 million related to this operational expense cap.

The Partnership recorded revenues from affiliates of $24.6 million and $48.8 million for the three and six months ended June 30, 2016, respectively, and $21.1 million and $28.5 million for the three and six months ended June 30, 2015, respectively, in accordance with the G&P Agreement, the NGL Agreement and the commercial agreements entered into in connection with the 2015 Holdings Acquisition.


23


We had accounts receivable due from affiliates of $16.3 million (includes the equity cure of $0.5 million due from Holdings related to the first quarter of 2016 that was paid in July 2016) and $49.7 million as of June 30, 2016 and December 31, 2015, respectively, and accounts payable due to affiliates of $7.3 million and $7.9 million as of June 30, 2016 and December 31, 2015, respectively. The affiliate receivable and payable balances are related primarily to transactions associated with Holdings, noted above, and our joint venture investments (defined in Note 12). The receivable balance due from Holdings is current as of June 30, 2016.

10. INCENTIVE COMPENSATION
Unit Based Compensation
Long-Term Incentive Plan
The 2012 Long-Term Incentive Plan (“LTIP”) provides incentive awards to eligible officers, employees and directors of our General Partner. Awards granted to employees under the LTIP vest over a three-year period in equal annual installments or in the event of a change in control of our General Partner in either a common unit or an amount of cash equal to the fair market value of a common unit at the time of vesting, as determined by management at its discretion. These awards also include distribution equivalent rights that grant the holder the right to receive an amount equal to the cash distributions on common units during the period the award remains outstanding.
On November 9, 2015, the holders of a majority of our limited partnership units approved an amendment to the LTIP which increased the number of common units that may be granted as awards by 4,500,000 units. The term of the LTIP was also extended to a period of 10 years following the amendment's adoption.
The following table summarizes information regarding awards of units granted under the LTIP: 
 
Units
 
Weighted-Average Fair
Value at Grant Date
Unvested - December 31, 2015
687,920

 
$
15.56

  Granted units
47,500

 
$
3.56

  Forfeited units
(32,265
)
 
$
17.03

  Units recaptured for tax withholdings
(41,605
)
 
$
12.80

  Vested units
(92,686
)
 
$
13.00

Unvested - June 30, 2016
568,864

 
$
14.86


For the six months ended June 30, 2016, we granted awards under the LTIP with a grant date fair value of $0.2 million which we have classified as equity awards. As of June 30, 2016, we had total unamortized compensation expense of $5.5 million related to unvested awards. Compensation expense associated with awards granted on March 10, 2015 of 84,423 units was recognized over a one-year vesting period, while compensation expense for the remaining awards is expected to be recognized over the three-year vesting period from each equity award’s grant date. As of June 30, 2016, we had 5,084,444 units available for issuance under the LTIP.

Unit Based Compensation Expense

The following table summarizes information regarding recognized compensation expense, which is included in general and administrative and operations and maintenance expense on our statements of operations (in thousands): 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Unit-based compensation
$
725

 
$
1,662

 
$
1,706

 
$
2,475


24


Employee Savings Plan
We have employee savings plans under Sections 401(a) and 401(k) of the Internal Revenue Code of 1986, as amended, whereby employees of our General Partner may contribute a portion of their base compensation to the employee savings plan, subject to limits. We provide a matching contribution each payroll period equal to 100% of each employee’s contribution up to the lesser of 6% of the employee’s eligible compensation or $18,000 annually for the period. The following table summarizes information regarding contributions and the expense recognized for the matching contributions, which is included in general and administrative expense on our statements of operations (in thousands): 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Matching contributions expensed for employee savings plan
$
399

 
$
172

 
$
608

 
$
340

11. REVENUES
 
We had revenues consisting of the following categories (in thousands): 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016

2015

2016

2015
Sales of natural gas
$
53,456

 
$
92,518

 
$
116,059

 
$
205,304

Sales of NGLs and condensate
41,832

 
39,427

 
68,022

 
76,610

Transportation, gathering and processing fees
28,157

 
33,823

 
57,292

 
68,876

Other
1,257

 
1,452

 
3,055

 
2,368

Total revenues
$
124,702

 
$
167,220

 
$
244,428

 
$
353,158

 
12. INVESTMENTS IN JOINT VENTURES

We own equity interests in three joint ventures with Targa Pipeline Partners LP as our joint venture partner. T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”), T2 LaSalle Gathering Company LLC (“T2 LaSalle”) and T2 EF Cogeneration Holdings LLC (“T2 Cogen”) operate pipelines and a cogeneration facility located in South Texas. We indirectly own a 50% interest in T2 Eagle Ford, a 50% interest in T2 Cogen and a 25% interest in T2 LaSalle. We pay our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization, through lease capacity payments. As a result, our share of the joint ventures’ losses is related primarily to the joint ventures’ depreciation and amortization. Our maximum exposure to loss related to these these joint ventures includes our equity investment, any additional capital contributions and our share of any operating expenses incurred by the joint ventures. The joint ventures’ summarized financial data from their statements of operations for the three and six months ended June 30, 2016 and 2015 is as follows (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Revenue
 
 
 
 
 
 
 
T2 Eagle Ford
$
1,642

 
$
1,215

 
$
3,044

 
$
2,136

T2 Cogen
1,077

 
1,187

 
1,999

 
2,849

T2 LaSalle
414

 
450

 
794

 
829

 
 
 
 
 
 
 
 
Net loss
 
 
 
 
 
 
 
T2 Eagle Ford
$
(4,924
)
 
$
(4,993
)
 
$
(9,511
)
 
$
(9,975
)
T2 Cogen
(1,424
)
 
(1,492
)
 
(2,966
)
 
(2,853
)
T2 LaSalle
(1,468
)
 
(1,445
)
 
(2,936
)
 
(2,965
)

25


Our equity in losses of joint venture investments is comprised of the following for the three and six months ended June 30, 2016 and 2015 (in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
T2 Eagle Ford
$
(2,462
)
 
$
(2,496
)
 
$
(4,755
)
 
$
(4,988
)
T2 Cogen
(709
)
 
(746
)
 
(1,479
)
 
(1,426
)
T2 LaSalle
(363
)
 
(362
)
 
(729
)
 
(741
)
Equity in losses of joint venture investments
$
(3,534
)
 
$
(3,604
)
 
$
(6,963
)
 
$
(7,155
)
Our investments in joint ventures is comprised of the following as of June 30, 2016 and December 31, 2015 (in thousands):
 
June 30, 2016
 
December 31, 2015
T2 Eagle Ford
$
106,411

 
$
105,755

T2 Cogen
14,872

 
16,747

T2 LaSalle
17,178

 
18,024

Investments in joint ventures
$
138,461

 
$
140,526


13. CONCENTRATION OF CREDIT RISK
 
Our primary markets are in South Texas, Alabama and Mississippi. We have a concentration of revenues and trade accounts receivable due from customers engaged in the production, trading, distribution and marketing of natural gas and NGL products. These concentrations of customers may affect overall credit risk in that these customers may be affected similarly by changes in economic, regulatory or other factors. We analyze our customers’ historical financial and operational information before extending credit.

Our top ten customers for the three and six months ended June 30, 2016 and 2015 represent the following percentages of consolidated revenue: 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Top ten customers
53.2
%
 
55.8
%
 
57.7
%
 
56.8
%
 
The percentage of total consolidated revenue for each customer that exceeded 10% of total revenues for the three and six months ended June 30, 2016 and 2015 was as follows: 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
TexStar Midstream(b)
10.3
%
 
(a)

 
11.4
%
 
(a)

Trafigura AG
(a)

 
13.0
%
 
(a)

 
11.8
%
 
(a) Information is not provided for periods for which the customer or producer was less than 10% of our consolidated revenue.
(b) TexStar Midstream is an indirectly wholly-owned subsidiary of Holdings.

For the six months ended June 30, 2016 and 2015, we did not experience significant non-payment for services. As of June 30, 2016 and December 31, 2015, we had an allowance for uncollectible accounts receivable of $0.1 million.
 
14. SUBSEQUENT EVENTS
 
On July 25, 2016, we determined Holdings’ cash contribution to us for the first quarter 2016 equity cure had not been transferred to us timely, as required under the Third A&R Revolving Credit Agreement due to an oversight, which resulted in a default. We advised the lenders under the Third A&R Revolving Credit Agreement, and on July 26, 2016, Holdings fully funded the first quarter 2016 equity cure. On August 4, 2016, we entered into the Limited Waiver and Second Amendment to the Third A&R Revolving Credit Agreement whereby the lenders waived any default or right to exercise any remedy as a result of this technical event of default to fund timely the first quarter 2016 equity cure.


26


15. SUPPLEMENTAL INFORMATION

Supplemental Cash Flow Information (in thousands)
 
Six Months Ended June 30,
 
2016
 
2015
Supplemental Disclosures:
 
 
 
Cash paid for interest, net of amounts capitalized
$
18,162

 
$
14,221

Cash received for tax refunds
53

 
58

Supplemental disclosures of non-cash investing and financing activities:
 
 
 
Accounts payable related to capital expenditures
2,796

 
9,615

Capital lease obligations

 
342

Accrued distribution equivalent rights on LTIP units
10

 
444

Class B Convertible unit in-kind distributions
1,293

 
6,706

Net assets contributed in Holdings drop-down acquisition in excess of consideration paid

 
29,716

Valley Wells' operating expense cap adjustment
1,415

 
518

Purchase of assets in Holdings drop-down acquisition

 
62,640

Net liabilities assumed by Holdings in Holdings drop-down acquisition

 
1,436

PIK interest
260

 

Common unit issuances to General Partner related to equity cures
245

 

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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Total interest costs
$
9,027

 
$
8,531

 
$
18,555

 
$
16,406

Capitalized interest included in property, plant and equipment, net
(194
)
 
(631
)
 
(552
)
 
(1,008
)
Interest expense
$
8,833

 
$
7,900

 
$
18,003

 
$
15,398

Southcross Assets Considered Leases to Third Parties
We have pipelines that 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 June 30, 2016 were as follows: $2.8 million for the remainder of 2016; $5.6 million in 2017; $2.2 million in 2018; $2.2 million in 2019; $2.2 million in 2020 and $13.1 million thereafter. The revenue for the demand payments is recognized on a straight-line basis over the term of the contract. The demand fee revenues under the contracts were $0.7 million and $1.3 million for the three and six months ended June 30, 2016 and 2015, respectively, and have been included within transportation, gathering and processing fees within Note 11. These amounts do not include variable fees based on the actual gas volumes delivered under the contracts. Variable fees recognized in revenues within transportation, gathering and processing fees within Note 11 were $0.8 million and $1.5 million for the three and six months ended June 30, 2016 and 2015, respectively. Deferred revenue associated with these agreements was $6.8 million and $5.3 million at June 30, 2016 and December 31, 2015, respectively.

27


Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

FORWARD-LOOKING INFORMATION
 
Investors are cautioned that certain statements contained in this report as well as in periodic press releases and oral statements made by our management team during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the section entitled “Risk Factors” included in our 2015 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 uncer