Attached files

file filename
EX-31.1 - EXHIBIT 31.1 - Southcross Energy Partners, L.P.a2015q310-qex311.htm
EX-32.1 - EXHIBIT 32.1 - Southcross Energy Partners, L.P.a2015q310-qex321.htm
EX-31.2 - EXHIBIT 31.2 - Southcross Energy Partners, L.P.a2015q310-qex312.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 September 30, 2015
 
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from             to             
 
Commission File Number: 001-35719
 
Southcross Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
 
DELAWARE
 
45-5045230
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
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
 
Indicate the number of units outstanding of the issuer’s classes of common units, subordinated units and Class B Convertible Units, as of the latest practicable date:
 
As of November 3, 2015, the registrant has 28,420,619 common units outstanding, 12,213,713 subordinated units outstanding and 15,684,512 Class B Convertible Units outstanding.  Our common units trade on the NYSE under the symbol “SXE.”



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

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

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

2


FORM 10-Q
TABLE OF CONTENTS
Southcross Energy Partners, L.P.
 
 
 
 
 
 
 
 
 
 
Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014
 
 
 
 
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014
 
 
 
 
Condensed Consolidated Statements of Comprehensive Loss for the Three and Nine Months Ended September 30, 2015 and 2014
 
 
 
 
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

3


FORWARD-LOOKING INFORMATION
 
Investors are cautioned that certain statements contained in this report as well as in periodic press releases and oral statements made by our management team during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries, are also forward-looking statements. These forward-looking statements involve external risks and uncertainties, including, but not limited to, those described under the section entitled “Risk Factors” included in our 2014 Annual Report on Form 10-K as updated by the Current Report on Form 8-K dated August 20, 2015.
 
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by these risks and uncertainties. These risks and uncertainties include, among others:
 
the volatility of natural gas, crude oil and NGL prices and the price and demand of products derived from these commodities, particularly in the depressed energy price environment that began in the second half of 2014, which has the potential for further deterioration and may result in a material reduction in exploration, development and production of crude oil or natural gas;
competitive conditions in our industry and the extent and success of producers increasing production or replacing declining production and our success in obtaining new sources of supply;
industry conditions and supply of pipelines, processing and fractionation capacity relative to available natural gas from producers;
our dependence upon a relatively limited number of customers for a significant portion of our revenues;
actions taken or inactions or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;
our ability to recover NGLs effectively at a rate equal to or greater than our contracted rates with customers;
our ability to produce and market NGLs at the anticipated differential to NGL index pricing;
our access to markets enabling us to match pricing indices for purchases and sales of natural gas and NGLs;
our ability to complete projects within budget and on schedule, including but not limited to, timely receipt of necessary government approvals and permits, our ability to control the costs of construction and other factors that may impact projects;
our ability to consummate acquisitions, successfully integrate the acquired businesses and realize anticipated cost savings and other synergies from any acquisitions, including with respect to our acquisition of certain gathering and processing assets from TexStar Midstream Services, LP in August 2014 and other assets acquired in May 2015;
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 financial covenants, and the potential for lack of access to debt and equity capital markets if the depressed energy price environment that began in the second half of 2014 continues;
our ability to generate sufficient operating cash flow to fund our quarterly distributions;
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, fractionation and treating 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;
changes in general economic conditions; and
other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the U.S. Securities and Exchange Commission.
 
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected, affect our ability to maintain distribution levels and/or access necessary financial markets or cause a significant reduction in the market price of our common units.
 

4


The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this report may not, in fact, occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to update publicly or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

5


PART I — FINANCIAL INFORMATION
 
Item 1. Financial Statements.
 
SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except for unit data)
(Unaudited)
 
September 30, 2015
 
December 31, 2014
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
1,651

 
$
1,649

Trade accounts receivable
43,765

 
74,086

Accounts receivable - affiliates
32,662

 
11,325

Prepaid expenses
4,238

 
3,073

Other current assets
3,174

 
1,813

Total current assets
85,490

 
91,946


 
 
 
Property, plant and equipment, net
1,074,664

 
1,058,570

Intangible assets, net
1,469

 
1,511

Investments in joint ventures
139,973

 
147,098

Other assets
27,159

 
17,189

Total assets
$
1,328,755

 
$
1,316,314

 
 
 
 
LIABILITIES AND PARTNERS’ CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
83,701

 
$
116,842

Accounts payable - affiliates
5,258

 
12,856

Current portion of long-term debt
4,500

 
4,500

Other current liabilities
12,238

 
12,773

Total current liabilities
105,697

 
146,971


 
 
 
Long-term debt
573,007

 
471,129

Other non-current liabilities
3,785

 
1,110

Total liabilities
682,489

 
619,210

 
 
 
 
Commitments and contingencies (Note 7)
 
 
 
 
 
 
 
Partners' capital:
 
 
 
Common units (28,418,156 and 23,800,943 units outstanding as of September 30, 2015 and December 31, 2014, respectively)
287,761

 
259,735

Class B Convertible units (15,684,512 and 14,889,078 units issued and outstanding as of September 30, 2015 and December 31, 2014, respectively)
304,930

 
298,833

Subordinated units (12,213,713 units issued and outstanding as of September 30, 2015 and December 31, 2014)
41,291

 
48,831

General partner interest
12,284

 
12,385

Southcross Holdings' equity in contributed subsidiaries

 
77,320

Total partners' capital
646,266

 
697,104

Total liabilities and partners' capital
$
1,328,755

 
$
1,316,314

 
See accompanying notes.

6


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

Nine Months Ended September 30,
 
2015

2014

2015

2014
Revenues:











Revenues
$
147,114


$
206,388


$
471,735


$
615,042

Revenues - affiliates
32,455


6,290


60,993


6,290

Total revenues
179,569


212,678


532,728


621,332













Expenses:
 





 


 

Cost of natural gas and liquids sold
133,401


180,562


399,111


535,791

Operations and maintenance
19,139


18,097


61,528


40,702

Depreciation and amortization
17,853


12,701


52,456


30,207

General and administrative
6,803


15,085


23,612


27,881

Impairment of assets


1,556


193


1,556

Loss (gain) on sale of assets, net
(33
)

334


146


292

Total expenses
177,163


228,335


537,046


636,429













Income (loss) from operations
2,406


(15,657
)

(4,318
)

(15,097
)
Other expense:











Equity in losses of joint venture investments
(3,567
)

(3,308
)

(10,722
)

(3,308
)
Interest expense
(8,688
)

(4,596
)

(24,087
)

(9,340
)
Loss on extinguishment of debt


(2,316
)



(2,316
)
Other expense


(86
)



(86
)
Total other expense
(12,255
)

(10,306
)

(34,809
)

(15,050
)
Loss before income tax benefit (expense)
(9,849
)

(25,963
)

(39,127
)

(30,147
)
Income tax benefit (expense)
190


(69
)

113


(133
)
Net loss
$
(9,659
)

$
(26,032
)

$
(39,014
)

$
(30,280
)
Series A Preferred unit fair value adjustment


424




(4,596
)
Series A Preferred unit in-kind distribution






(534
)
General partner unit in-kind distribution
(28
)

(112
)

(165
)

(123
)
Net loss attributable to Holdings


(1,254
)

(4,258
)

(1,254
)
Net loss attributable to partners
$
(9,687
)

$
(24,466
)

$
(34,921
)

$
(34,279
)












Earnings per unit and distributions declared











Net loss allocated to limited partner common units
$
(4,799
)

$
(11,156
)

$
(16,711
)

$
(19,084
)
Weighted average number of limited partner common units outstanding
28,372

22,926

26,234

20,911
Basic and diluted loss per common unit
$
(0.17
)

$
(0.49
)

$
(0.64
)

$
(0.91
)












Net loss allocated to limited partner subordinated units
$
(2,065
)

$
(6,009
)

$
(7,777
)

$
(7,795
)
Weighted average number of limited partner subordinated units outstanding
12,214

12,214

12,214

12,214
Basic and diluted loss per subordinated unit
$
(0.17
)

$
(0.49
)

$
(0.64
)

$
(0.64
)
Distributions declared per common unit
$
0.40


$
0.40


$
1.20


$
1.20

 
See accompanying notes.

7


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
(Unaudited)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Net loss
$
(9,659
)
 
$
(26,032
)
 
$
(39,014
)
 
$
(30,280
)
Other comprehensive income (loss):
 

 
 

 
 

 
 

Hedging losses reclassified to earnings and recognized in interest expense

 

 

 
221

Adjustment in fair value of derivatives

 

 

 
(11
)
Total other comprehensive income

 

 

 
210

Comprehensive loss
$
(9,659
)
 
$
(26,032
)
 
$
(39,014
)
 
$
(30,070
)
 
See accompanying notes.

8


SOUTHCROSS ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited) 
 
Nine Months Ended September 30,
 
2015
 
2014
Cash flows from operating activities:
 
 
 
Net loss
$
(39,014
)
 
$
(30,280
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation and amortization
52,456

 
30,207

Unit-based compensation
3,513

 
10,837

Amortization of deferred financing costs
2,615

 
3,596

Loss on sale of assets, net
146

 
292

Unrealized loss on financial instruments
289

 
539

Equity in losses of joint venture investments
10,722

 
3,308

Distribution from joint venture investment
500

 

Impairment of assets
193

 
1,556

Other, net
(69
)
 
81

Changes in operating assets and liabilities:
 
 
 
Trade accounts receivable, including affiliates
5,613

 
(10,517
)
Prepaid expenses and other current assets
(1,516
)
 
(1,066
)
Other non-current assets
77

 
(34
)
Accounts payable and accrued liabilities
(14,180
)
 
10,043

Other liabilities, including affiliates
3,163

 
2,343

Net cash provided by operating activities
24,508

 
20,905

Cash flows from investing activities:


 


Capital expenditures
(93,946
)
 
(103,370
)
Expenditures for assets subject to property damage claims, net of insurance proceeds and deductibles
(2,482
)
 
(796
)
Proceeds from sales of assets
4,693

 
1,758

Investment contribution to joint venture investments
(2,474
)
 
(105
)
Consideration paid for Holdings' drop-down acquisition
(15,000
)
 

TexStar Rich Gas System acquisition from affiliate

 
(79,955
)
Other acquisitions

 
(38,636
)
Net cash used in investing activities
(109,209
)
 
(221,104
)
Cash flows from financing activities:


 


Proceeds from issuance of common units, net

 
144,671

Borrowings under our credit facility
136,000

 
184,000

Borrowings under our term loan agreement

 
450,000

Repayments under our credit facility
(31,000
)
 
(442,300
)
Repayments under our term loan agreement
(3,375
)
 
(1,125
)
Payments on capital lease obligations
(406
)
 
(454
)
Financing costs
(685
)
 
(17,716
)
Contributions from general partner
1,301

 
9,967

Payments of distributions and distribution equivalent rights
(35,088
)
 
(42,711
)
Expenses paid by Holdings on behalf of Valley Wells' assets
17,858

 
17,872

Assumption and repayment of debt in TexStar Rich Gas System Transaction

 
(100,000
)
Valley Wells operating expense cap adjustment
518

 

Other, net
(420
)
 
(3,532
)
Net cash provided by financing activities
84,703

 
198,672

 
 
 
 
Net increase (decrease) in cash and cash equivalents
2

 
(1,527
)
Cash and cash equivalents — Beginning of period
1,649

 
3,349

Cash and cash equivalents — End of period
$
1,651

 
$
1,822


See accompanying notes.

9


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

 
Partners' Capital

 

 
Limited Partners



 

 


Common

Class B Convertible
 
Subordinated

General Partner

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

(16,583
)
 
(9,722
)
 
(7,755
)
 
(696
)
 
(4,258
)
 
(39,014
)
Contributions from general partner


 

 

 
1,301

 

 
1,301

Class B Convertible unit in-kind distribution

(5,340
)
 
8,059

 
(2,557
)
 
(162
)
 

 

Unit-based compensation on long-term incentive plan

3,384

 

 

 

 

 
3,384

Cash distributions and distribution equivalent rights paid
 
(30,366
)
 

 
(3,432
)
 
(1,290
)
 

 
(35,088
)
Accrued distribution equivalent rights on long-term incentive plan
 
(703
)
 

 

 

 

 
(703
)
Tax withholdings on unit-based compensation vested units
 
(419
)
 

 

 

 

 
(419
)
General partner unit in-kind distribution
 
(112
)
 

 
(53
)
 
165

 

 

Valley Wells' operating expense cap adjustment
 
1,023

 

 

 

 

 
1,023

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
 
14,502

 
7,760

 
6,257

 
581

 
(29,100
)
 

Expenses paid by Holdings on behalf of Valley Wells' assets
 

 

 

 

 
17,858

 
17,858

Net liabilities assumed by Holdings in Holdings drop-down acquisition
 

 

 

 

 
820

 
820

BALANCE - September 30, 2015
 
$
287,761

 
$
304,930

 
$
41,291

 
$
12,284

 
$

 
$
646,266




10


 
Partners' Capital
 
 
 
 
Limited Partners
 
 
 
 
 
 
 
 
 
Common
 
Class B Convertible
 
Subordinated
 
General Partner
 
Southcross Holdings' equity in contributed subsidiaries
 
Accumulated Other Comprehensive Loss
 
Total
BALANCE - December 31, 2013
$
169,141

 
$

 
$
99,726

 
$
6,367

 
$

 
$
(210
)
 
$
275,024

Net loss
(15,356
)
 
(6,778
)
 
(7,565
)
 
(581
)
 

 

 
(30,280
)
Issuance of common units, net
144,671

 

 

 

 

 

 
144,671

Issuance of Class B Convertible units, net

 
324,413

 

 

 

 

 
324,413

Consideration paid in excess of purchase price for the TexStar Rich Gas System
(45,420
)
 
(27,925
)
 
(23,308
)
 
(1,972
)
 

 

 
(98,625
)
Contributions from general partner

 

 

 
9,967

 

 

 
9,967

Class B Convertible unit in-kind distribution
(3,533
)
 
5,467

 
(1,824
)
 
(110
)
 

 

 

Unit-based compensation on long-term incentive plan
9,236

 

 

 

 

 

 
9,236

Series A Preferred conversion into common units
45,624

 

 

 

 

 

 
45,624

Series A Preferred unit in-kind distribution and fair value adjustments
(3,126
)
 

 
(1,897
)
 
(107
)
 

 

 
(5,130
)
Cash distributions and distribution equivalent rights paid
(26,566
)
 

 
(14,657
)
 
(869
)
 

 

 
(42,092
)
Accrued distribution equivalent rights on long-term incentive plan
(562
)
 

 

 

 

 

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

 

 

 

 

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

 
(45
)
 
123

 

 

 

Net effect of cash flow hedges

 

 

 

 

 
210

 
210

Expenses paid by Southcross Holdings on behalf of Valley Wells and Compressor Assets

 

 

 

 
17,872

 

 
17,872

BALANCE - September 30, 2014
$
270,499

 
$
295,177

 
$
50,430

 
$
12,818

 
$
17,872

 
$

 
$
646,796



See accompanying notes.

11


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

Until August 4, 2014, Southcross Energy LLC, a Delaware limited liability company, held all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”), all of our subordinated units and a portion of our common units. Southcross Energy LLC is controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”).

Holdings Transaction

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

TexStar Rich Gas System Transaction

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

Holdings Drop-Down Acquisition

On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “2015 Holdings Acquisition”) from Holdings and its subsidiaries consisting of the Valley Wells sour gas gathering and treating system, compression assets that are part of the Valley Wells and Lancaster gathering and treating systems and two NGL pipelines. For additional details regarding the 2015 Holdings Acquisition, see Notes 2 and 9.

Liquidity Consideration
Beginning in the second half of 2014 and continuing through the issuance of these financial statements, commodity prices have experienced increased volatility. In particular, natural gas, crude oil and NGL prices have decreased significantly. If a material reduction in drilling for oil or natural gas continues in the geographic areas in which we operate, including the Eagle Ford Shale region, or significant, prolonged pricing deterioration continues for commodities we sell, our future cash flow may be materially adversely affected.
The majority of our revenue is derived from fixed-fee contracts, which have limited direct exposure to commodity price levels since we are paid based on the volumes of natural gas that we gather, process, treat, compress and transport and the volumes of NGLs we fractionate and transport, rather than being paid based on the value of the underlying natural gas or NGLs. In addition, a percentage of our contract portfolio contains minimum volume commitment arrangements. The majority of our volumes are dependent upon the level of producer drilling activity.
After considering these uncertainties, we anticipate potential future shortfalls in the amount of consolidated EBITDA (as defined in the Third Amended and Restated Revolving Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”), 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)

12


in our Credit Facility. As discussed in further detail in Note 6, we have the 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 would also experience a cross default under our Term Loan Agreement (defined in Note 6) and all of our debt would become due and payable to our lenders.
As of September 30, 2015, we determined that we will not be in compliance with the consolidated total leverage ratio of our Financial Covenants absent an equity cure of approximately $5.3 million within approximately 15 days following the issuance of these financial statements. We believe that we will have the ability to fund this equity cure with the remaining $8.3 million non-cash equity cure credit amount from our Credit Agreement Amendment (as defined in Note 6). We used $4.7 million of the contractual $13.0 million non-cash equity cure credit amount from our Credit Agreement Amendment to fund an equity cure as of June 30, 2015 in order to stay in compliance with the consolidated total leverage ratio of our Financial Covenants. We anticipate funding additional equity cures needed to maintain compliance with our Financial Covenants through the end of 2016 with the remainder of the non-cash equity cure credit amount, the $50 million Sponsor equity commitment described below, or a combination of the two.
In response to our need for additional liquidity and to maintain compliance with our Financial Covenants, our Sponsors have committed to provide the necessary funding to support us for at least a reasonable period of time in an amount up to $50 million, which was increased from $25 million in August 2015, to ensure we have sufficient liquidity to comply with applicable Financial Covenants and to fund normal operating and growth capital requirements. Therefore, these financial statements have been presented as if we will continue as a going concern. See Note 6.
Description of Business
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.
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 2014 Annual Report on Form 10-K as updated by the Current Report on Form 8-K dated August 20, 2015 (“2014 Annual Report on Form 10-K”). The condensed consolidated financial statements as of September 30, 2015 and December 31, 2014, and for the three and nine months ended September 30, 2015 and 2014, are unaudited and have been prepared on the same basis as the audited financial statements included in our 2014 Annual Report on Form 10-K. Adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations and financial position have been included herein. All intercompany accounts and transactions have been eliminated in the preparation of the accompanying condensed consolidated financial statements.

The condensed consolidated financial statements reflect the assets acquired and liabilities assumed and the related operating results associated with (i) the Onyx pipelines acquisition on March 6, 2014, (ii) the TexStar Rich Gas System Transaction and the 2015 Holdings Acquisition on August 4, 2014, (iii) and the Texoz acquisition on November 21, 2014. See Note 2.

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


13


Additionally, because the TexStar Rich Gas System was owned by TexStar, the Partnership recorded the TexStar Rich Gas System at TexStar’s historical cost. Thus, the difference between consideration paid and the TexStar Rich Gas System’s historical cost (net book value) at August 4, 2014, the date on which the Holdings Transaction and the TexStar Rich Gas System Transaction closed, was recorded as a reduction to partners’ capital. Management concluded that the Partnership was the predecessor for accounting purposes for periods prior to August 4, 2014.

We recognized the 2015 Holdings Acquisition 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 a reduction 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 2014 Annual Report on Form 10-K.
 
We evaluate events that occur after the balance sheet date, but before the financial statements are issued, for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed in this report.

Significant Accounting Policies
 
During the third quarter of 2015, there were no material changes to our significant accounting policies described in Note 1 of our 2014 Annual Report on Form 10-K.
 
Recent Accounting Pronouncements
 
Accounting standard-setting organizations frequently issue new or revised accounting 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 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 July 2015, the Financial Accounting Standards Board (“FASB”) voted to defer the new revenue recognition standard. The standard is currently set to be effective in the first quarter of 2018.

In February 2015, the FASB issued a pronouncement that amended current consolidation guidance with regard to variable interest entities and voting interest entities. This standard will become effective beginning in 2016.

In April 2015, the FASB issued a pronouncement simplifying the presentation of debt issuance costs effective beginning in 2016. The amendment requires that debt issuance costs related to a recognized debt liability be presented on the balance sheet as a reduction to the carrying amount of that debt liability, consistent with the presentation for debt discounts. The recognition and measurement guidance for debt issuance costs is not affected by the amendments. In August 2015, the FASB further clarified that the SEC staff would not object to a similar capitalization and amortization of deferred issuance costs for line of credit arrangements.

In April 2015, the FASB issued a pronouncement that specifies how to calculate historical earnings per unit for a master limited partnership with retrospectively adjusted financial statements subsequent to a drop-down acquisition. The amendments specify that for purposes of calculating historical earnings per unit under the two-class method, the earnings or losses of a transferred business before the date of a drop-down acquisition are to be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners would not change as a result of the drop-down acquisition. Qualitative disclosures about how the rights to the earnings or losses differ before and after the drop-down

14


acquisition occurs for purposes of computing earnings per unit under the two-class method are also required. This standard will become effective beginning in 2016, however we have elected to early adopt this standard in this report. See Note 3.

In September 2015, the FASB issued a pronouncement simplifying the recognition of provisional amounts that are identified during the measurement period of an acquisition. The amendments require an entity to present separately on the face of the income statement or disclose in the notes to the financial statements the portion of the amount recorded in the current period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. This standard will become effective beginning in 2016.

2. ACQUISITIONS

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

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

Current assets
 
$
1,295

Property, plant and equipment, net
 
255,220

Investments in joint ventures(2)
 
152,050

Total assets contributed
 
408,565

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

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

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

Class B Convertible limited partner interest
 
27,925

Subordinated limited partner interest
 
23,308

General Partner interest
 
1,972

Total reduction to partners' capital
 
$
98,625

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

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

The fair values of the property, plant and equipment were based upon then current assumptions related to expected future cash flows, discount rates and asset lives. We utilized a mix of the cost, income and market approaches to determine the

15


estimated fair values of such assets. The fair value measurements and models were classified as non-recurring Level 3 measurements.
We performed our assessment of the fair value of the assets acquired and liabilities assumed, and determined that the consideration given was equal to the fair value of net assets acquired. As a result, no goodwill was recorded. The assessment was finalized during the second quarter of 2014 and there were no changes to the preliminary balances recorded.
The fair value of the assets acquired and liabilities assumed related to the Onyx purchase price was as follows (in thousands):
Purchase Price—Cash
$
38,636

Current assets
$
730

Property, plant and equipment
39,413

Total assets acquired
40,143

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

Unaudited Pro Forma Financial Information for Onyx Pipelines Acquisition. The following unaudited pro forma financial information for the nine months ended September 30, 2014 assumes that the acquisition of pipelines from Onyx occurred on January 1, 2013 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the transaction (in thousands, except per unit information):
 
Nine Months Ended September 30,
 
2014
Total revenue
$
620,796

Net loss
(29,104
)
Net loss attributable to common unitholders
(19,132
)
Net loss per common unit (basic and diluted)
(0.91
)
Net loss attributable to subordinated unitholders
(7,823
)
Net loss per subordinated unit (basic and diluted)
(0.64
)
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 September 30, 2014, the Onyx pipelines business contributed $3.0 million in revenues and $0.9 million in net income to our statements of operations.
Texoz Acquisition. On November 21, 2014, we completed the acquisition of a natural gas gathering system in McMullen County, Texas (the “Texoz System”) from LT Gathering, LLC for $5.4 million in cash, net of certain adjustments as provided in the purchase agreement (the “Texoz Acquisition”). The Texoz System consists of eight miles of gathering pipelines within two miles of our existing rich gas pipeline network and services customers under acreage dedication contracts. Due to the immaterial amount of this transaction, no pro-forma financial information has been presented.
Holdings Drop-Down Acquisition. On May 7, 2015, we completed the 2015 Holdings Acquisition pursuant to a Purchase, Sale and Contribution Agreement among Holdings, TexStar Midstream Utility, LP, Frio LaSalle Pipeline, LP (“Frio”), us and certain of our subsidiaries. The acquired assets consist of the Valley Wells sour gas gathering and treating system (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. 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, issued to Holdings. Also, we assumed the remaining capital expenditures for the completion of the NGL pipelines that were under construction at the time of acquisition.
The Valley Wells System is located in the Eagle Ford Shale region, in LaSalle County, Texas. The system has sour gas treating capacity of approximately 100 MMcf/d and is supported by a 60 MMcf/d minimum volume commitment from Holdings for gathering and treating services, while Holdings has producer contracts with minimum volume commitments totaling 35 MMcf/d behind the system. The system is connected to our rich gas system for transport and processing. The assets acquired in the 2015 Holdings Acquisition include over 50,000 horsepower of compression capability that serve both the Valley

16


Wells and Lancaster gathering systems located primarily in Dimmit, Frio and LaSalle counties. The NGL pipelines, which were completed in June 2015, include a Y-grade pipeline that connects our Woodsboro processing facility to Holdings’ Robstown fractionator (“Robstown”) and a propane pipeline from our Bonnie View fractionator to Robstown.
Because of the common control aspects in the 2015 Holdings Acquisition, 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 Valley Wells’ and Compression Assets’ financial results 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 have been included in the historical financial statements beginning on May 7, 2015. As a carve-out transaction, the 2015 Holdings Acquisition has 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. We are still evaluating the effect of certain liabilities at our parent company and how they should be treated going forward. 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
 
106,740

Net assets contributed in excess of consideration paid
 
$
29,100

Allocation of increase to partners' capital:
 
 
Common limited partner interest
 
$
14,502

Class B Convertible limited partner interest
 
7,760

Subordinated limited partner interest
 
6,257

General Partner interest
 
581

Total increase to partners' capital
 
$
29,100

 
(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. Revenues and net income for the previously separate entities and the combined amounts for the nine months ended September 30, 2015 and three and nine months ended September 30, 2014, are as follows (in thousands):
 
Nine Months Ended September 30, 2015
 
Three Months Ended September 30, 2014
 
Nine months ended September 30, 2014
Partnership revenues
$
525,679

 
$
211,493

 
$
620,147

Valley Wells System and Compression Assets revenue(1)
7,049

 
1,185

 
1,185

Combined revenues
$
532,728

 
$
212,678

 
$
621,332

 
 
 
 
 
 
Partnership net loss
$
(34,756
)
 
$
(24,778
)
 
$
(29,026
)
Valley Wells System and Compression Assets net loss(1)
(4,258
)
 
(1,254
)
 
(1,254
)
Combined net loss
$
(39,014
)
 
$
(26,032
)
 
$
(30,280
)

(1) Results are fully reflected in the Partnership’s results of operations for the nine months ended September 30, 2015.



17


3. NET LOSS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS
 
Net Loss Per Limited Partner Unit
 
The following is a reconciliation of the net loss attributable to our limited partners and our limited partner units and the basic and diluted earnings per unit calculations for the three and nine months ended September 30, 2015 and 2014 (in thousands, except unit and per unit data): 
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
Net loss
 
$
(9,659
)
 
$
(26,032
)
 
$
(39,014
)
 
$
(30,280
)
Series A Preferred unit fair value adjustment (1)
 

 
424

 

 
(4,596
)
Series A Preferred unit in-kind distribution
 

 

 

 
(534
)
General partner unit in-kind distribution
 
(28
)
 
(112
)
 
(165
)
 
(123
)
Net loss attributable to Holdings
 

 
(1,254
)
 
(4,258
)
 
(1,254
)
Net loss attributable to partners
 
$
(9,687
)
 
$
(24,466
)
 
$
(34,921
)
 
$
(34,279
)
 
 
 
 
 
 
 
 
 
General partner's interest (2)
 
$
(201
)
 
$
(523
)
 
$
(711
)
 
$
(622
)
Class B Convertible limited partner interest (2)
 
(2,622
)
 
(6,778
)
 
(9,722
)
 
(6,778
)
Limited partners' interest (2)
 
 
 
 
 
 
 
 
    Common
 
$
(4,799
)
 
$
(11,156
)
 
$
(16,711
)
 
$
(19,084
)
    Subordinated
 
(2,065
)
 
(6,009
)
 
(7,777
)
 
(7,795
)

(1) The valuation adjustment to maximum redemption value of the Series A Preferred unit in-kind distribution decreased the net loss attributable to partners for the three months ended September 30, 2014 and increased the net loss attributable to partners for the nine months ended September 30, 2014.

(2) General Partner's and limited partners’ interests are calculated based on the allocation of net losses for the period, net of the allocation of Series A Preferred unit in-kind distributions, Series A Preferred Unit fair value adjustments and General Partner unit in-kind distributions. The Class B Convertible Unit interest is calculated based on the allocation of only net losses for the period.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Common Units
 
2015
 
2014
 
2015
 
2014
Interest in net loss
 
$
(4,799
)
 
$
(11,156
)
 
$
(16,711
)
 
$
(19,084
)
Effect of dilutive units - numerator (1)
 

 

 

 

    Dilutive interest in net loss
 
$
(4,799
)
 
$
(11,156
)
 
$
(16,711
)
 
$
(19,084
)
 
 
 
 
 
 
 
 
 
Weighted-average units - basic
 
28,371,903

 
22,925,979

 
26,233,614

 
20,911,472

Effect of dilutive units - denominator (1)
 

 

 

 

    Weighted-average units - dilutive
 
28,371,903

 
22,925,979

 
26,233,614

 
20,911,472

 
 
 
 
 
 
 
 
 
Basic and diluted net loss per common unit
 
$
(0.17
)
 
$
(0.49
)
 
$
(0.64
)
 
$
(0.91
)


18


 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Subordinated Units
 
2015
 
2014
 
2015
 
2014
Interest in net loss
 
$
(2,065
)
 
$
(6,009
)
 
$
(7,777
)
 
$
(7,795
)
Effect of dilutive units - numerator(1)
 

 

 

 

    Dilutive interest in net loss
 
$
(2,065
)
 
$
(6,009
)
 
$
(7,777
)
 
$
(7,795
)
 
 
 
 
 
 
 
 
 
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
 
$
(0.17
)
 
$
(0.49
)
 
$
(0.64
)
 
$
(0.64
)

(1) Because we had a net loss for all periods for common units and the subordinated units, the effect of the dilutive units would be anti-dilutive to the per unit calculation. Therefore, the weighted average units outstanding are the same for basic and dilutive net loss per unit for those periods. The weighted average units that were not included in the computation of diluted per unit amounts were 4,526 and 11,464 for the three and nine months ended September 30, 2015, respectively.
 
Our calculation of the number of weighted-average units outstanding includes the common units that have been awarded to our directors that are deferred under our Non-Employee Director Deferred Compensation Plan.

All of our Series A Preferred Units were converted into common units on August 4, 2014 (see Note 8). Prior to conversion, our Series A Preferred Units were considered participating securities for purposes of the basic earnings per unit calculation during periods in which they received cash distributions. We were required to pay in-kind distributions to the Series A Preferred Units for the first four full quarters beginning the second quarter of 2013, and continued to pay these distributions until the Series A Preferred Units were converted into common units. Because the Series A Preferred Units received in-kind distributions, they have been excluded from the basic earnings per unit calculation for the three and nine months ended September 30, 2014.
 
Distributions
 
Our agreement of limited partnership, which was amended and restated on August 4, 2014 in order to establish the Class B Convertible Units (as amended and restated, our “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. Subject to the waiver and credit agreement restriction, described below, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our General Partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Beginning with the third quarter of 2014, until such time that we have a distributable cash flow divided by cash distributions ratio (“Distributable Cash Flow Ratio”) of at least 1.0, Holdings, the 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.

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

19


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

The following table represents the paid in-kind (“PIK”) distribution declared in 2014 through August 4, 2014, the date on which all outstanding Series A Preferred Units were converted to common units (in thousands, except per unit and in-kind distribution units): 
Payment Date
 
Attributable to the Quarter Ended(1)
 
Per Unit Distribution
 
In-Kind Series A
Preferred Unit
Distributions to Series A Preferred Holders
 
In-Kind 
Series A
Preferred
Distributions
Value
(2)
 
In-Kind 
Unit
Distribution
to General 
Partner
 
In-Kind General Partner Distribution Value(2)
2014
 
 
 
 
 
 
 
 
 
 
 
 
May 15, 2014
 
March 31, 2014
 
$
0.40

 
31,513

 
$
534

 
643

 
$
11


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

Class B Convertible Units. In connection with the Contribution and the TexStar Rich Gas System Transaction, on August 4, 2014, we established our Class B Convertible Units. As of September 30, 2015, the Class B Convertible Units consisted of 15,684,512 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 paid in Class B PIK Units (based on a unit issuance price of $18.61) within 45 days after the end of each quarter. Our General Partner was entitled, and has exercised its right, to retain its 2.0% general partner interest in us in connection with the original issuance of 14,633,000 Class B Convertible Units. In connection with future distributions of Class B PIK Units, the General Partner is entitled to a corresponding distribution to maintain its 2.0% general partner interest in us. The Class B Convertible Units have the same rights, preferences and privileges, and are subject to the same duties and obligations, as our common units, with certain exceptions. See Note 9.


20


The following table presents the PIK distribution earned on the Class B Convertible Units for periods after issuance on August 4, 2014 through September 30, 2015 (in thousands, except per unit and in-kind distribution units):
Payment Date
 
Attributable to the Quarter Ended
 
Per Unit Distribution
 
In-Kind Class B Convertible Unit
Distributions to Class B Convertible Holders
 
In-Kind 
Class B Convertible Distributions
Value
(1)
 
In-Kind 
Unit
Distribution
to General 
Partner
 
In-Kind General Partner Distribution Value(1)
2015
 
 
 
 
 
 
 
 
 
 
 
 
November 13, 2015
 
September 30, 2015
 
$
0.3257

 
274,478

 
$
1,353

 
5,601

 
$
28

August 14, 2015
 
June 30, 2015
 
0.3257

 
269,758

 
2,994

 
5,505

 
61

May 14, 2015
 
March 31, 2015
 
0.3257

 
265,118

 
3,712

 
5,410

 
76

2014
 
 
 
 
 
 
 
 
 
 
 
 
February 13, 2015
 
December 31, 2014
 
0.3257

 
260,558

 
4,143

 
5,318

 
85

November 14, 2014
 
September 30, 2014
 
0.3257

 
256,078

 
5,467

 
5,226

 
112

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

Cash Distributions
 
The following table represents our distributions declared for the quarterly periods beginning in 2014 through the nine months ended September 30, 2015 (in thousands, except per unit data): 
 
 
 
 
 
 
Distributions
 
 
 
 
Attributable to the
 
Per Unit
 
Limited Partners
 
 
 
 
Payment Date
 
Quarter Ended
 
Distribution
 
Common
 
Subordinated
 
General Partner
 
Total
2015
 
 
 
 
 
 
 
 
 
 
 
 
November 13, 2015
 
September 30, 2015
 
$
0.40

 
$
11,367

 
$

 
$
459

 
$
11,826

August 14, 2015
 
June 30, 2015
 
0.40

 
11,325

 

 
457

 
11,782

May 14, 2015
 
March 31, 2015
 
0.40

 
9,520

 

 
418

 
9,938

2014
 
 
 
 
 
 
 
 
 
 
 
 
February 13, 2015
 
December 31, 2014
 
0.40

(1) 
9,520

 
3,432

(2) 
416

 
13,368

November 14, 2014
 
September 30, 2014
 
0.40

(1) 
9,520

 

 
413

 
9,933

August 14, 2014
 
June 30, 2014
 
0.40

 
9,399

 
4,886

 
290

 
14,575

May 15, 2014
 
March 31, 2014
 
0.40

 
8,586

 
4,886

 
290

 
13,762


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

4. FINANCIAL INSTRUMENTS

Fair Value Measurements

We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable inputs that represent market data obtained from independent sources to unobservable inputs that reflect our own market assumptions that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:

21


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.

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

The interest rate swap was designated as a cash flow hedge for accounting purposes at inception of the contract and, thus, to the extent the cash flow hedge was effective, unrealized gains and losses were recorded to accumulated other comprehensive income/loss and recognized in interest expense as the underlying hedged transactions (interest payments) were recorded. Any hedge ineffectiveness was recognized in interest expense immediately. We did not have any hedge ineffectiveness during the three and nine months ended September 30, 2014.

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

The effect of the interest rate swap designated as a cash flow hedge in our statements of changes in partners’ capital and comprehensive loss was as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2014
Change in value recognized in other comprehensive loss - effective portion
$

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

 
221

 
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.


22


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
 
September 30, 2015
$
50,000

 
1.198
%
 
September 30, 2014
 
June 30, 2016
 
$
(71
)
50,000

 
1.196
%
 
September 30, 2014
 
June 30, 2016
 
(70
)
100,000

 
1.195
%
 
June 30, 2015
 
January 1, 2017
 
(190
)
 
 
 
 
 
 
 
 
$
(331
)

We enter into interest rate cap contracts to effectively limit our 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
 
September 30, 2015
$
20,000

 
1.500
%
 
December 31, 2014
 
December 31, 2016
 
$
3

80,000

 
3.000
%
 
June 30, 2015
 
June 30, 2017
 
6

 
 
 
 
 
 
 
 
$
9


These interest rate derivatives are not designated as cash flow hedges 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 on the balance sheets. There was no effect of offsetting on the balance sheets as of September 30, 2015 or December 31, 2014.

The fair values of our interest rate derivatives were as follows (in thousands):
 
Significant Other Observable Inputs (Level 2)
 
Fair Value Measurement as of
 
September 30, 2015
 
December 31, 2014
Current interest rate derivative assets
$
6

 
$
27

Non-current interest rate derivative assets
3

 
27

Current interest rate derivative (liabilities)
(293
)
 
(175
)
Non-current interest rate derivative (liabilities)
(38
)
 
(39
)
Total interest rate derivatives
$
(322
)
 
$
(160
)
 
The realized and unrealized amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Unrealized gain (loss) on interest rate derivatives
$
(53
)
 
$
21

 
$
(163
)
 
$
201

Realized gain (loss) on interest rate derivatives
(100
)
 
74

 
(357
)
 
127

 
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. The total volume of outstanding month-ahead swap contracts as of September 30, 2015 and December 31, 2014 was 10,000 and 12,000 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.


23


We have elected to present our commodity swaps net on the balance sheets. We did not have any cash collateral received or paid on our commodity swaps as of September 30, 2015 or December 31, 2014. The effect of offsetting on our balance sheets was as follows (in thousands):
 
September 30, 2015
 
December 31, 2014
 
Other Current Assets
 
Other Current Liabilities
 
Other Current Assets
 
Other Current Liabilities
Gross amounts of recognized assets
$

 
$

 
$
112

 
$

Gross amounts offset on the balance sheets

 

 

 

Net amount
$

 
$

 
$
112

 
$

The realized and unrealized gain/loss on these derivatives, recognized in revenues in our statements of operations, was as follows (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Realized gain (loss) on commodity swap derivatives
$
11

 
$
213

 
$
147

 
$
(875
)
Unrealized gain (loss) on commodity swap derivatives
(15
)
 
(207
)
 
(126
)
 
(338
)
5. LONG-LIVED ASSETS
Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
 
Estimated
Useful Life (yrs)
 
September 30, 2015
 
December 31, 2014
Pipelines
15-30
 
$
540,061

 
$
488,592

Gas processing, treating and other plants
15
 
545,439

 
515,080

Compressors
7-15
 
69,131

 
62,741

Rights of way and easements
15
 
46,358

 
37,238

Furniture, fixtures and equipment
5
 
10,792

 
3,671

Capital lease vehicles
3-5
 
2,442

 
2,076

    Total property, plant and equipment
 
 
1,214,223

 
1,109,398

Accumulated depreciation and amortization
 
 
(194,648
)
 
(142,234
)
    Total
 
 
1,019,575

 
967,164

Construction in progress
 
 
29,698

 
63,858

Land and other
 
 
25,391

 
27,548

    Property, plant and equipment, net
 
 
$
1,074,664

 
$
1,058,570

 
Depreciation is provided using the straight-line method based on the estimated useful life of each asset. 
 
In January 2015, we shut down our Gregory facility for four weeks due to a fire at the facility. We reached our insurance deductible as part of efforts to return the facility to service from the fire and recorded a receivable in our condensed consolidated balance sheets as of September 30, 2015 for amounts incurred above the deductible.
 
Intangible Assets

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


24


6. LONG-TERM DEBT 

Our outstanding debt and related information at September 30, 2015 and December 31, 2014 are as follows (in thousands):
 
September 30, 2015
 
December 31, 2014
Revolving credit facility due 2019
$
135,000

 
$
30,000

Term loans (including OID of $1.9 million) due 2021
442,507

 
445,629

Total long-term debt (including current portion)
577,507

 
475,629

Current portion of long-term debt
$
(4,500
)
 
$
(4,500
)
Total long-term debt
$
573,007

 
$
471,129

Outstanding letters of credit
$
22,110

 
$
30,130

Remaining unused borrowings
$
42,890

 
$
139,870

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015

2014

2015

2014
Weighted average interest rate
5.19
%
 
4.80
%
 
5.15
%
 
4.20
%
Average outstanding borrowings
$
585,283

 
$
372,072

 
$
549,342

 
$
252,005

Maximum borrowings
$
596,500

 
$
465,000

 
$
596,500

 
$
465,000


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

Senior Credit Facilities

On August 4, 2014, in connection with the consummation of the Contribution and TexStar Rich Gas System Transaction, we entered into (a) the Third A&R Revolving Credit Agreement (as defined in Note 1) and (b) a Term Loan Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). The initial borrowings and extensions of credit under the Term Loan Agreement were used to finance the TexStar Rich Gas System Transaction (including the immediate repayment of the $100 million of debt assumed in the transaction), the repayment of certain of our existing debt and the payment of fees and expenses in connection with the new debt arrangements and ongoing working capital and other general partnership purposes. No amounts were drawn initially on the Third A&R Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Senior Credit Facilities, with the security interest of the facilities ranking pari passu.

Third A&R Revolving Credit Agreement

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

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

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


25


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

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

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

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

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

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

Amendment to Third A&R Revolving Credit Agreement

During the fourth quarter of 2014 and into the first quarter of 2015, as a result of the decline in commodity prices and associated decline in upstream drilling activity, we experienced a decline in the growth in volume of natural gas we gather and process for our customers. Our results in the first quarter of 2015 also were negatively impacted by the fire at our Gregory facility (see Note 5). These collective events impacted our operating results adversely and resulted in the need to amend our Third A&R Revolving Credit Agreement.

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

The Credit Agreement Amendment, among other things:

(a) (i) revised the maximum consolidated total leverage ratio set at 5.75 to 1.0 as of the last day of the fiscal quarter ending each of March 31, 2015, June 30, 2015 and September 30, 2015, (ii) 5.5 to 1.0 as of the last day of the fiscal quarter ending each of December 31, 2015, March 31, 2016 and June 30, 2016, (iii) 5.25 to 1.0 as of the last day of the fiscal quarter ending September 30, 2016, and (iv) 5.00 to 1.0 as of the last day of each fiscal quarter thereafter, in each case, without any step-ups in connection with acquisitions;

(b) increased the applicable margins used in connection with the loans and the commitment fee so that the applicable margin for Eurodollar Loans (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%;

(c) permits the Partnership to comply with certain Financial Covenants by making certain pro forma adjustments with respect to minimum revenues to be received from Frio;

(d) modified our ability to cure Financial Covenant defaults;

(e) imposed additional restrictions on our ability to declare and pay quarterly cash distributions with respect to our subordinated units;

(f) amended certain other provisions of the Third A&R Revolving Credit Agreement as more specifically set forth in the Credit Agreement Amendment; and


26


(g) 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. Additionally, we are unable to borrow on our Credit Facility until we have funded the required equity cure for the third quarter of 2015; however, we retain the ability to fund the required equity cure using a contractual non-cash credit amount of up to $13 million, $4.7 million of which was used to fund an equity cure in order to stay in compliance with the consolidated total leverage ratio for our Financial Covenants as of June 30, 2015.

Term Loan Agreement

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

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

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

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

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

(e)
the facility 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;

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

(g)
there are customary representations and warranties, affirmative covenants, negative covenants and provisions governing an event of default (including acceleration of payment in connection with material indebtedness, including the Third A&R Revolving Credit Agreement).