Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

x                QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended September 30, 2012

 

OR

 

o                   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from             to            

 

Commission File Number: 001-35719

 

Southcross Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

 

DELAWARE

 

45-5045230

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

1700 Pacific Avenue, Suite 2900

Dallas, TX

 

75201

(Address of principal executive offices)

 

(Zip Code)

 

(214) 979-3700

(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 o No x

 

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 x 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 o

 

 

 

Non-accelerated filer x
(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 x

 

Indicate the number of units outstanding of the issuer’s classes of common units, subordinated units and General Partner units, as of the latest practicable date:

 

Class

 

As of December 10, 2012

 

Common Units

 

 

12,213,713

 

Subordinated Units

 

 

12,213,713

 

General Partner Units

 

 

     498,518

 

 

 



Table of Contents

 

Explanatory Note

 

As generally used in the energy industry and in this report, the following terms have the following meanings:

 

/d:  Per day

Bbls:  Barrels

Condensate:  Hydrocarbons that are produced from natural gas reservoirs but remain liquid at normal temperature and pressure

Lean gas:  Natural gas that is low in NGL content

MMBtu:  One million British thermal units

Mcf:  One thousand cubic feet

Mgal: One thousand gallons

MMcf:  One million cubic feet

NGLs:  Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate

Residue gas:  The pipeline quality natural gas remaining after natural gas is processed and NGLs removed

Rich gas:  Natural gas that is high in NGL content

Throughput:  The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility

 

Southcross Energy LLC and Southcross Energy Partners, L.P:

 

Southcross Energy LLC, a Delaware limited liability company, is the predecessor for accounting purposes (the “Predecessor”) of Southcross Energy Partners, L.P. (the “Partnership”). The accompanying financial statements and related notes include the assets, liabilities, results of operations and cash flows of the Predecessor prior to the Predecessors’ contribution of its subsidiaries to the Partnership in connection with the Partnership’s initial public offering (“IPO”).

 

On November 7, 2012, the Partnership completed its IPO. Also, on November 7, 2012, in connection with the closing of the IPO, the following transactions occurred:

 

·                  The Predecessor conveyed all of its limited liability company interests in its operating subsidiaries to Southcross Energy Operating, LLC (“Southcross Operating”) as a capital contribution;

 

·                  The Predecessor conveyed a limited liability company interest in Southcross Operating to Southcross Energy Partners GP, LLC, the Partnership’s general partner (the “General Partner”) as a capital contribution with a value equal to 2.0% of the equity value of the Partnership (the “GP Contribution Interest”);

 

·                  The General Partner conveyed the GP Contribution Interest to the Partnership in exchange for (i) 498,518 general partner units in the Partnership representing a continuation of its 2.0% general partner interest; and (ii) the Partnership’s incentive distribution rights (“IDRs”);

 

·                  The Predecessor conveyed its remaining interest in Southcross Operating to the Partnership in exchange for (i) 3,213,713 common units (1,863,713 common units subsequent to the purchase of 1,350,000 common units from the Predecessor when the underwriters fully exercised their over-allotment option on November 26, 2012 (the “Over-Allotment Option”)) representing a 12.9% limited partner interest (7.5% limited partner interest, including the exercise of the Over-Allotment Option on November 26, 2012), (ii) 12,213,713 subordinated units representing a 49.0% limited partner interest, (iii) the Partnership’s assumption of the Predecessor’s outstanding debt under its credit agreement, (iv) the right to receive $7.5 million sourced from new debt the Partnership incurred and (v) the right to receive $38.5 million in cash, a portion of which was used to reimburse the Predecessor for certain capital expenditures it incurred with respect to the contributed assets;

 

·                  Pursuant to the Partnership’s long term incentive plan, the Partnership granted 146,000 phantom units, with distribution equivalent rights, to certain of our employees;

 

·                  The Partnership issued 9,000,000 common units to the public (10,350,000 common units including the exercise of the Over-Allotment Option);

 

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·                  The Partnership used the proceeds from the IPO, net of underwriters’ and structuring fees, plus borrowings under the Partnership’s senior secured credit facility to (i) repay the outstanding debt under the Predecessor’s credit agreement of $270.0 million, (ii) make cash distributions to the Predecessor of $38.5 million including reimbursements for certain capital expenditures the Predecessor incurred with respect to assets the Predecessor contributed to the Partnership and (iii) distribute $7.5 million to the Predecessor;

 

·                  The Partnership utilized $25.2 million representing the funds received in connection with the Over-Allotment Option to purchase and retire 1,350,000 common units from the Predecessor; and

 

·                  The Predecessor used the combined proceeds from the IPO and the Over-Allotment Option of $71.2 million ($46.0 million and $25.2 million, respectively) received from the Partnership to redeem Series B Redeemable Preferred units and Series C Redeemable Preferred units of the Predecessor.

 

The financial statements in this report reflect the Predecessor’s financial statements.  The effects of the IPO and related transactions occurring in November 2012 are not reflected in these financial statements.

 

The results of the Predecessor for the three and nine month periods ended September 30, 2012 may not be indicative of the Partnership’s future financial results.

 

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FORM 10-Q

TABLE OF CONTENTS

Southcross Energy Partners, L.P.

 

PART I — FINANCIAL INFORMATION

5

 

 

ITEM 1.

PREDECESSOR FINANCIAL STATEMENTS (UNAUDITED)

5

 

 

 

 

Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011

5

 

 

 

 

Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011

6

 

 

 

 

Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2012 and 2011

7

 

 

 

 

Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011

8

 

 

 

 

Condensed Consolidated Statement of Members’ Equity for the Nine Months Ended September 30, 2012 and 2011

9

 

 

 

 

Notes to Condensed Consolidated Financial Statements

10

 

 

 

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

24

 

 

 

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

34

 

 

 

ITEM 4.

CONTROLS AND PROCEDURES

34

 

 

 

PART II — OTHER INFORMATION

35

 

 

ITEM 1.

LEGAL PROCEEDINGS

35

ITEM 1A.

RISK FACTORS

35

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

35

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

35

ITEM 4.

MINE SAFETY DISCLOSURES

35

ITEM 5.

OTHER INFORMATION

35

 

 

 

ITEM 6.

EXHIBITS

36

 

 

 

SIGNATURES

37

 

 

4



Table of Contents

 

PART I — FINANCIAL INFORMATION

 

Item 1. Financial Statements.

 

SOUTHCROSS ENERGY LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit information)

(Unaudited)

 

 

 

September 30,

 

December 31,

 

 

 

2012

 

2011

 

ASSETS

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

3,893

 

$

1,412

 

Trade accounts receivable

 

43,526

 

41,234

 

Prepaid expenses

 

1,404

 

950

 

Other current assets

 

311

 

561

 

Total current assets

 

49,134

 

44,157

 

 

 

 

 

 

 

Property, plant and equipment, net

 

485,041

 

369,861

 

Intangible assets, net

 

1,638

 

1,681

 

Other assets

 

7,850

 

4,686

 

Total assets

 

$

543,663

 

$

420,385

 

 

 

 

 

 

 

LIABILITIES, PREFERRED UNITS AND MEMBERS’ EQUITY

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

65,821

 

$

50,439

 

Interest payable

 

99

 

24

 

Current maturities of long term debt

 

17,490

 

17,490

 

Other current liabilities

 

6,442

 

4,983

 

Total current liabilities

 

89,852

 

72,936

 

 

 

 

 

 

 

Long term debt

 

235,673

 

190,790

 

Other noncurrent liabilities

 

421

 

21

 

Total liabilities

 

325,946

 

263,747

 

 

 

 

 

 

 

Commitments and contingencies (Note 12)

 

 

 

 

 

 

 

 

 

 

 

Preferred units:

 

 

 

 

 

Redeemable preferred units

 

18,892

 

16,554

 

Series B redeemable preferred units

 

46,622

 

 

Series C redeemable preferred units

 

31,423

 

 

Preferred units

 

161,819

 

150,249

 

 

 

 

 

 

 

Members’ equity:

 

 

 

 

 

Common equity—Class A (1,313,445 and 1,415,729 common units authorized
and outstanding as of September 30, 2012 and December 31, 2011, respectively)

 

1,313

 

1,416

 

Common equity—Class B (28,639 and 57,279 units authorized and outstanding as of September 30, 2012 and December 31, 2011, respectively)

 

29

 

57

 

Accumulated other comprehensive loss

 

(559

)

 

Accumulated deficit

 

(41,822

)

(11,638

)

Total members’ equity

 

(41,039

)

(10,165

)

Total liabilities, preferred units and members’ equity

 

$

543,663

 

$

420,385

 

 

See accompanying notes to these unaudited condensed consolidated financial statements.

 

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SOUTHCROSS ENERGY LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except unit information)

(Unaudited)

 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Total revenue

 

$

118,150

 

$

135,961

 

$

344,469

 

$

383,450

 

Expenses:

 

 

 

 

 

 

 

 

 

Cost of natural gas and liquids sold

 

103,073

 

122,489

 

289,277

 

339,614

 

Operations and maintenance

 

8,890

 

6,471

 

24,469

 

16,764

 

Depreciation and amortization

 

5,522

 

3,019

 

12,860

 

8,621

 

General and administrative

 

3,351

 

2,498

 

8,987

 

6,725

 

Total expenses

 

120,836

 

134,477

 

335,593

 

371,724

 

 

 

 

 

 

 

 

 

 

 

(Loss) income from operations

 

(2,686

)

1,484

 

8,876

 

11,726

 

Loss on extinguishment of debt

 

 

 

 

(3,240

)

Interest expense

 

(1,362

)

(1,251

)

(4,493

)

(4,053

)

 

 

 

 

 

 

 

 

 

 

(Loss) income before income tax expense

 

(4,048

)

233

 

4,383

 

4,433

 

Income tax benefit (expense)

 

7

 

(34

)

(249

)

(200

)

 

 

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(4,041

)

$

199

 

$

4,134

 

$

4,233

 

 

 

 

 

 

 

 

 

 

 

Less deemed dividend on:

 

 

 

 

 

 

 

 

 

Redeemable preferred units

 

(820

)

(688

)

(2,339

)

(835

)

Series B redeemable preferred units

 

(2,038

)

 

(3,822

)

 

Series C redeemable preferred units

 

(1,364

)

 

(1,423

)

 

Preferred units

 

(3,978

)

(3,603

)

(11,564

)

(10,437

)

 

 

 

 

 

 

 

 

 

 

Net loss attributable to common unitholders

 

$

(12,241

)

$

(4,092

)

$

(15,014

)

$

(7,039

)

 

 

 

 

 

 

 

 

 

 

Net loss per unit—(basic and diluted)

 

$

(10.09

)

$

(3.36

)

$

(12.36

)

$

(5.81

)

 

 

 

 

 

 

 

 

 

 

Weighted average number of common units outstanding

 

1,213,496

 

1,216,301

 

1,214,321

 

1,211,515

 

 

See accompanying notes to these unaudited condensed consolidated financial statements.

 

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SOUTHCROSS ENERGY LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

 

 

 

Three months ended September 30,

 

Nine months ended September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(4,041

)

$

199

 

$

4,134

 

$

4,233

 

Other comprehensive (loss) income

 

 

 

 

 

 

 

 

 

Hedging losses reclassified to earnings

 

84

 

 

169

 

 

Adjustment in fair value of derivatives

 

(379

)

 

(728

)

 

Total other comprehensive loss

 

(295

)

 

(559

)

 

Comprehensive (loss) income

 

$

(4,336

)

$

199

 

$

3,575

 

$

4,233

 

 

See accompanying notes to these unaudited condensed consolidated financial statements.

 

7



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SOUTHCROSS ENERGY LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

 

 

Nine Months Ended September 30,

 

 

 

2012

 

2011

 

Cash Flows From Operating Activities:

 

 

 

 

 

Net income

 

$

4,134

 

$

4,233

 

 

 

 

 

 

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Depreciation and amortization

 

12,860

 

8,621

 

Compensation expense under accrued liability awards

 

293

 

 

Loss on extinguishment of debt

 

 

3,240

 

Deferred financing fees amortization

 

948

 

713

 

Gain on sale of property, plant and equipment

 

 

(522

)

Unrealized derivatives loss

 

222

 

27

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(2,292

)

(1,942

)

Prepaid expenses and other

 

(198

)

(141

)

Other non-current assets

 

(1,598

)

(1,620

)

Accounts payable

 

(166

)

204

 

Interest payable

 

75

 

(1,779

)

Accrued expenses and other liabilities

 

784

 

969

 

Net cash provided by operating activities

 

15,062

 

12,003

 

Cash Flows From Investing Activities:

 

 

 

 

 

Capital expenditures

 

(112,450

)

(76,172

)

Acquisition of Enterprise Alabama Intrastate, LLC

 

 

(21,777

)

Sale of property, plant and equipment

 

 

522

 

Net cash used in investing activities

 

(112,450

)

(97,427

)

Cash Flows From Financing Activities:

 

 

 

 

 

Borrowings under revolving credit facility

 

88,500

 

9,500

 

Repayment of revolving credit facility

 

(30,500

)

(9,500

)

Proceeds under long-term debt

 

 

174,900

 

Repayment of long-term debt

 

(13,118

)

(122,247

)

Financing costs

 

(2,513

)

(2,665

)

Repayment of equity note

 

 

113

 

Repurchase and retirement of common units

 

(15,300

)

 

Proceeds from issuance of redeemable preferred units

 

 

15,000

 

Proceeds from issuance of Series B redeemable preferred units

 

42,800

 

 

Proceeds from issuance of Series C redeemable preferred units

 

30,000

 

 

Net cash provided by financing activities

 

99,869

 

65,101

 

 

 

 

 

 

 

Net increase(decrease) in cash and cash equivalents

 

2,481

 

(20,323

)

Cash and cash equivalents—Beginning of period

 

1,412

 

20,323

 

Cash and cash equivalents—End of period

 

$

3,893

 

$

 

 

 

 

 

 

 

Cash paid for interest

 

$

7,820

 

$

6,040

 

Cash paid for taxes

 

$

320

 

$

272

 

 

 

 

 

 

 

Non-cash transactions:

 

 

 

 

 

Accounts payable related to capital expenditures

 

$

26,410

 

$

15,198

 

 

See accompanying notes to the condensed consolidated financial statements.

 

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SOUTHCROSS ENERGY LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

(In thousands)

(Unaudited)

 

 

 

Common
Equity

 

Accumulated
Deficit

 

Accumulated
Other
Comprehensive
Loss

 

Total Members’
Equity

 

Balance, December 31, 2010

 

$

1,472

 

$

(3,493

)

$

 

$

(2,021

)

Net income

 

 

 

4,233

 

 

 

4,233

 

Deemed dividend on:

 

 

 

 

 

 

 

 

 

Redeemable Preferred Units

 

 

 

(835

)

 

 

(835

)

Preferred Units

 

 

 

(10,437

)

 

 

(10,437

)

 

 

 

 

 

 

 

 

 

 

Balance, September 30, 2011

 

$

1,472

 

$

(10,532

)

$

 

$

(9,060

)

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2011

 

$

1,473

 

$

(11,638

)

$

 

$

(10,165

)

Net income

 

 

 

4,134

 

 

 

4,134

 

Net effect of cash flow hedges

 

 

 

 

 

(559

)

(559

)

Deemed dividend on:

 

 

 

 

 

 

 

 

 

Redeemable Preferred Units

 

 

 

(2,339

)

 

 

(2,339

)

Series B Redeemable Preferred Units

 

 

 

(3,822

)

 

 

(3,822

)

Series C Redeemable Preferred Units

 

 

 

(1,423

)

 

 

(1,423

)

Preferred Units

 

 

 

(11,564

)

 

 

(11,564

)

Repurchase and retirement of common units

 

(131

)

(15,170

)

 

 

(15,301

)

 

 

 

 

 

 

 

 

 

 

Balance, September 30, 2012

 

$

1,342

 

$

(41,822

)

$

(559

)

$

(41,039

)

 

See accompanying notes to these unaudited condensed consolidated financial statements.

 

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SOUTHCROSS ENERGY LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

 

1.              ORGANIZATION AND BASIS OF PRESENTATION

 

Organization

 

On November 7, 2012, Southcross Energy Partners, L.P. (the “Partnership”) completed its initial public offering (the “IPO”) and after the completion of the IPO and full exercise of the underwriters’ over-allotment option, Southcross Energy LLC, a Delaware limited liability company and the predecessor for accounting purposes of the Partnership (the “Predecessor”) (collectively, the Partnership and the Predecessor are herein referred to as the “Company,” “we,” “us” and “our”) owns all of the equity interests in Southcross Energy Partners GP, LLC, the Partnership’s general partner (the “General Partner”) as well as common and subordinated units of the Partnership. The Predecessor’s total direct and indirect equity ownership in the partnership is 58.5%. The accompanying condensed consolidated financial statements as of September 30, 2012 and December 31, 2011 and for the three and nine months ended September 30, 2012 and 2011 reflect the financial and operating results of the Predecessor.

 

The Predecessor, formed on June 2, 2009, and its subsidiaries are controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”).

 

The following activities occurred in connection with the closing of the IPO:

 

Activity of the Predecessor

 

·                  The Predecessor conveyed the following:

·                  its direct and indirect ownership in its operating subsidiaries to Southcross Energy Operating, LLC, the Partnership’s operating subsidiary (“Southcross Operating”);

·                  an interest in Southcross Operating to the General Partner as a capital contribution; and

·                  its remaining interest in Southcross Operating to the Partnership in exchange for:

·                  3,213,713 common units, representing a 12.9% limited partner interest in the Partnership;

·                  12,213,713 subordinated units, representing a 49.0% limited partner interest in the Partnership; and

·                  the assumption by the Partnership of the Predecessor’s existing debt under its credit agreement of $270.0 million, which included an additional $5.0 million in borrowings during November 2012.

·                  The Predecessor paid the accumulated 18% priority return on both Series B Redeemable Preferred units and Series C Redeemable Preferred units accrued through the IPO closing date and redeemed all of the outstanding Series C Redeemable Preferred units and approximately 22% of the outstanding Series B Redeemable Preferred units, by paying $46.0 million to the owners of such redeemable preferred units.

 

Activity of the General Partner

 

·                  The General Partner conveyed its interest in Southcross Operating to the Partnership in exchange for:

·                  a continuation of its 2% general partner interest in the Partnership; and

·                  the Partnership’s incentive distribution rights (“IDR”).

 

Activity of the Partnership

 

·                  The Partnership used the proceeds from its IPO of approximately $168.0 million, net of underwriters’ and structuring fees to:

·                  repay $129.5 million of debt outstanding under the Predecessor’s credit agreement which the Partnership assumed; and

·                  to make a $38.5 million distribution, including reimbursements for certain capital expenditures, to the Predecessor.

·                  The Partnership issued 9,000,000 common units to the public, representing a 36.1% limited partner interest in the Partnership;

 

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·                  The Partnership established a long term incentive plan and granted 146,000 phantom units with distribution equivalent rights to certain employees.

·                  The Partnership entered into a $350.0 million senior secured credit facility and borrowed $150.0 million.  The Partnership used proceeds of $147.5 million (net of $2.5 million in lender fees and expenses) for repayment of $140.0 million of the Predecessor’s debt and $7.5 million for distribution to the Predecessor;

·                  The Partnership retired all of the Predecessor’s assumed debt of $270.0 million then outstanding under the Predecessor’s credit agreement; and

·                  The Partnership assumed responsibility for all of the Predecessor’s $26.7 million of outstanding letters of credit.

 

Subsequent to the IPO and the concurrent activity by the Company, the Partnership owns the Predecessors’ operating subsidiaries and will continue to provide the services of the Predecessor.

 

In connection with the full exercise of the underwriter’s over-allotment option which closed on November 26, 2012 (the “Over-Allotment Option”), the following occurred:

 

Activity of the Partnership

 

·                  The Partnership’s underwriters purchased 1,350,000 additional common units in the Partnership for approximately $25.2 million in proceeds, net of underwriters’ and structuring fees;

·                  The Partnership used the net proceeds of $25.2 million to acquire 1,350,000 common units from the Predecessor; and

·                  The Partnership redeemed and retired the 1,350,000 common units acquired from the Predecessor.

 

Activity of the Predecessor

 

·                  The Predecessor used a portion of the proceeds from the redemption of the common units to pay the accumulated 18% priority return on the outstanding Series B Redeemable Preferred units of $313,684;

·                  The Predecessor used the remaining proceeds of approximately $24.9 million to redeem 2,489,081 Series B Redeemable Preferred units from the owners of the units resulting in 858,717 Series B Redeemable Preferred units outstanding, which will remain the obligation of the Predecessor; and

·                  The Predecessor subsequently held 1,863,713 common units representing, with its 12,213,713 subordinated units, a 56.5% limited partner interest in the Partnership and 498,518 general partner units representing a 2.0% general partner interest in the Partnership.

 

The Company is a midstream natural gas company with operations in Texas, Mississippi and Alabama. The Company operates as one reportable segment and provides natural gas gathering, processing, treating, compression and transportation services and natural gas liquids (“NGL”) fractionation and transportation services for its producer customers, and sources, purchases, transports and sells natural gas and NGLs to power generation, industrial and utility customers.

 

Organizational Structure

 

The following table depicts the ownership structure following the IPO and the Over-Allotment Option:

 

Description

 

Percentage Ownership

 

Public Common Units

 

41.5

%

Southcross Energy LLC:

 

 

 

Common Units

 

7.5

%

Subordinated Units

 

49.0

%

General Partner Interest

 

2.0

%

Total

 

100.0

%

 

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Basis of Presentation

 

These unaudited interim condensed consolidated financial statements for the Predecessor were prepared under the rules and regulations of the Securities and Exchange Commission (“SEC”) and in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements. Accordingly, these financial statements do not include all of the disclosures required by GAAP and should be read along with the Predecessor’s 2011 audited consolidated financial statements and related notes included in the Partnership’s Rule 424(b)(4) Prospectus filed with the SEC on November 2, 2012 (the “Prospectus”). The Predecessor’s financial statements as of September 30, 2012, and for the three and nine months ended September 30, 2012 and 2011, are unaudited and have been prepared on the same basis as the annual consolidated financial statements.  All intercompany accounts and transactions have been eliminated in the preparation of the accompanying financial statements.

 

In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for the fair presentation of the results of operations for the three and nine months ended September 30, 2012 and 2011.  Information for interim periods may not be indicative of the Predecessor’s operating results for the entire year.

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Use of Estimates

 

The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the financial statements as well as the reported amounts of revenues and expenses during the reporting periods. Although these estimates are based on management’s best available knowledge of current and future events, actual results may differ from those estimates.

 

Significant Accounting Policies

 

There were no changes to the significant accounting policies described in the Predecessor’s 2011 audited consolidated financial statements and related notes included in the Prospectus.  For information on our significant accounting policies, see Note 2 of the Predecessor’s 2011 audited consolidated financial statements included in the Prospectus.

 

Recent Accounting Pronouncements -  Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review new pronouncements to determine the impact, if any, on our consolidated financial statements.

 

Effective January 1, 2012, the Predecessor adopted the revised accounting guidance associated with the presentation of comprehensive income, which did not have a material impact on the financial statements. There were no other new pronouncements that had or are expected to have a material impact on the Predecessor’s financial statements.

 

3. ACQUISITIONS

 

Enterprise Alabama Intrastate, LLC

 

The Predecessor completed the acquisition of Enterprise Alabama Intrastate, LLC (“EAI”) from Enterprise GTM Holdings L.P. for $21.8 million on September 1, 2011. EAI owns approximately 388 miles of two to sixteen inch natural gas pipeline assets located in northwest and central Alabama, provides gathering, transportation and compression services and engages in the purchase and sale of natural gas.  EAI’s identifiable assets acquired and liabilities assumed by the Predecessor were recorded based upon the fair values determined on the date of acquisition.

 

The fair values of the EAI property, plant and equipment were determined based upon assumptions related to expected future cash flows, discount rates and asset lives using currently available information. The Company utilized a mix of the cost, income and market approaches in determining the estimated fair values of such assets. The fair value measurements and models are classified as non-recurring level 3 measurements consistent with accounting standards related to the determination of fair value.

 

The Predecessor completed its assessment of the fair value of the assets acquired and liabilities assumed as of March 31, 2012 and determined the consideration given was equal to the fair value of net assets acquired; thus, no goodwill was recorded.

 

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The reconciliation of the fair values of the assets acquired and liabilities assumed related to the EAI purchase price was as follows (in thousands):

 

Purchase Price - Cash

 

$

21,777

 

 

 

 

 

Fair Value of Identifiable Assets Acquired

 

 

 

Current assets

 

$

3,374

 

Property, plant and equipment

 

19,300

 

Intangible assets

 

1,700

 

Total assets acquired

 

$

24,374

 

 

 

 

 

Current liabilities

 

2,597

 

Total liabilities assumed

 

2,597

 

 

 

 

 

Net identifiable assets acquired

 

$

21,777

 

 

The Predecessor attributed $1.7 million to intangible assets associated with long term supply and gathering contracts assumed in the acquisition (See Note 5).

 

In the third quarter of 2011, the Predecessor expensed $0.2 million of transaction costs associated with the acquisition of EAI.  These costs are reported within general and administrative expenses.

 

The following unaudited pro forma financial information of the Predecessor assumes that the EAI acquisition occurred on January 1, 2011 and includes adjustments for income from operations, including depreciation and amortization, as well as the effects of financing the acquisition (in thousands, except unit information):

 

 

 

Three months ended
September 30, 2011

 

Nine months ended
September 30, 2011

 

 

 

Predecessor

 

Combined

 

Predecessor

 

Combined

 

Total revenue

 

$

135,961

 

$

141,844

 

$

383,450

 

$

408,453

 

Net income

 

$

199

 

$

123

 

$

4,233

 

$

4,891

 

Net loss attributable to common unitholders

 

$

(4,092

)

$

(4,168

)

$

(7,039

)

$

(6,381

)

 

 

 

 

 

 

 

 

 

 

Net loss per unit - (basic and diluted)

 

$

(3.37

)

$

(3.43

)

$

(5.81

)

$

(5.27

)

 

The unaudited pro forma information is not necessarily indicative of what the Predecessor’s results of operations would have been if the transaction had occurred on that date, or what the Partnership’s financial position or results from operations will be for any future periods.

 

Both revenue and net income generated by EAI are immaterial for the period between the EAI acquisition date (September 1, 2011) and September 30, 2011.

 

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4. PROPERTY, PLANT AND EQUIPMENT

 

Property, plant and equipment consisted of the following (in thousands):

 

Description

 

Useful life

 

September 30,
2012

 

December 31,
2011

 

Pipeline

 

30

 

$

232,469

 

$

230,866

 

Gas processing, treating and other plants

 

15

 

145,197

 

36,990

 

Compressors

 

7

 

19,241

 

16,078

 

Rights of way

 

15

 

20,729

 

20,249

 

Furniture, fixtures and equipment

 

5

 

3,050

 

2,814

 

Total property, plant and equipment

 

 

 

$

420,686

 

$

306,997

 

Accumulated depreciation and amortization

 

 

 

(40,365

)

(27,547

)

Total

 

 

 

$

380,321

 

$

279,450

 

 

 

 

 

 

 

 

 

Construction in progress

 

 

 

100,978

 

86,189

 

Land and other

 

 

 

3,742

 

4,222

 

Net property, plant and equipment

 

 

 

$

485,041

 

$

369,861

 

 

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

 

Costs related to projects during construction, including interest on funds borrowed to finance the construction of facilities, are capitalized as construction in progress.  For the three months ended September 30, 2012 and 2011, the Predecessor capitalized interest of $2.2 million and $0.6 million, respectively. For the nine months ended September 30, 2012 and 2011, the Predecessor capitalized interest of $4.5 million and $0.9 million, respectively.

 

5. INTANGIBLE ASSETS

 

Intangible assets of $1.6 million and $1.7 million as of September 30, 2012 and December 31, 2011, respectively, represent the value assigned to the long term supply and gathering contracts assumed by the Predecessor in the EAI acquisition. The majority of assumed contracts are life of lease, and the Predecessor determined that the useful economic lives of the underlying producing leases were at least as long as the expected life of the acquired pipelines.  These intangible assets are amortized on a straight line basis over the 30 year expected useful lives of the contracts.  Amortization expense related to intangible assets for the periods presented was not material.

 

6. OTHER ASSETS

 

Other assets consisted of the following (in thousands):

 

Description

 

September 30,
2012

 

December 31,
2011

 

Deferred financing costs

 

$

3,721

 

$

2,155

 

Prepaid offering costs

 

3,599

 

2,040

 

Other

 

530

 

491

 

Total other assets

 

$

7,850

 

$

4,686

 

 

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The Predecessor deferred certain costs and fees incurred in conjunction with its financing under its credit agreement dated June 10, 2011 (the “Credit Agreement”). These deferred costs were being amortized to interest expense over the five-year term of the Credit Agreement.

 

The Predecessor incurred $2.3 million in costs as a result of entering into an amendment of the Credit Agreement on February 7, 2012, which modified the existing agreement. These deferred financing costs, along with the then existing unamortized deferred financing costs of $2.2 million, are being amortized over the remaining life of the Credit Agreement through the maturity date of June 10, 2016 and were reflected in Other Assets. Amortization of deferred financing costs was as follows (in thousands):

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Amortization of deferred financing costs

 

$

322

 

$

173

 

$

947

 

$

713

 

 

7. LONG TERM DEBT

 

For the nine months ended September 30, 2012, the Predecessor had weighted average borrowings outstanding under the Credit Agreement of $236.3 million at an effective average interest rate of 3.85%. For the nine months ended September 30, 2011, the Predecessor had weighted average borrowings outstanding under the Credit Agreement of $131.7 million at an effective average interest rate of 3.64%. As of September 30, 2012, the Predecessor had an outstanding term loan of $150.2 million with a LIBOR based interest rate of 4.47% and a revolver loan of $103.0 million with an effective interest rate of 4.47%, excluding the effects of any hedging. As of September 30, 2012, the Predecessor was in compliance with all of its financial loan covenants.

 

Amendment to the Credit Agreement—February 7, 2012

 

On February 7, 2012, the Predecessor entered into the first amendment of the Credit Agreement. The amendment was accounted for as a modification of an existing debt agreement and was entered into in order to modify the covenants to reflect the Predecessor’s need for expansion capital to support its growth plans. This amendment did not change the term loan or revolver loan capacity, but eased financial covenant measures and modified loan pricing for when the Predecessor’s leverage ratio was greater than 5.0 times.

 

On November 7, 2012, the Partnership, in connection with the IPO, assumed and repaid $270.0 million, representing all of the Predecessor’s outstanding debt under the Credit Agreement at that time (See Note 1).

 

Additionally, in connection with the closing of the IPO, the Partnership entered into a $350.0 million senior secured credit facility with Wells Fargo Bank, N.A., and a syndicate of lenders (the “Senior Secured Credit Facility”).  The Partnership utilized the Senior Secured Credit Facility to fund fees and expenses incurred in connection with the IPO and for the repayment of a portion of the Predecessor’s debt.

 

The Partnership may utilize the Senior Secured Credit Facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions, repurchase of units and general purposes of the Partnership. The interest rate on this facility as of the IPO date was LIBOR plus 3.25%.  The Senior Secured Credit Facility matures on November 7, 2017, the fifth anniversary of the IPO closing date.

 

In addition, the Senior Secured Credit Facility includes a sublimit of up to $75.0 million for letters of credit. Substantially all of the Partnership’s assets are pledged as collateral under the Senior Secured Credit Facility. The Senior Secured Credit Facility contains various covenants and restrictive provisions and also requires maintenance of certain financial and operational covenants including but not limited to the following:

 

·                  prior to exercising a one-time covenant election in connection with the issuance of certain unsecured notes, a consolidated total leverage ratio (generally defined as debt to EBITDA, as adjusted) of not more than 5.25 to 1.00 with step downs as set forth in the Senior Secured Credit Facility, and a consolidated interest coverage ratio of not less than 2.75 to 1.00. The requirement to maintain a certain consolidated total leverage ratio is subject to a provision for increases to 5.00 to 1.00 in connection with certain future acquisitions;

 

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Table of Contents

 

·                  upon exercising a one-time covenant election in connection with the issuance of certain unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.00, a consolidated senior secured leverage ratio of not more than 3.50 to 1.00 and a consolidated interest coverage ratio of not less than 2.75 to 1.00;

 

·                  by December 31, 2012 the Bonnie View fractionation facility must have processed at least an average of 7,000 Bbls/d per day over a period of seven consecutive days; and

 

·                  by December 31, 2012 the Woodsboro gas processing facility must have processed at least an average of 80 MMcf/d per day over a period of seven consecutive days.

 

8. MEMBERS’ EQUITY

 

As of September 30, 2012, the Predecessor’s common equity was comprised of 1,313,445 Class A common units, of which 114,580 were unvested, and 28,639 Class B units, of which 11,456 were unvested. As of December 31, 2011, the Predecessor’s common equity was comprised of 1,415,729 Class A common units, of which 217,483 were unvested, and 57,279 Class B units, of which 34,367 were unvested. The Class B units have the same distribution and liquidation rights as the Class A common units; however, they do not have voting rights. All Class A common units and Class B units were purchased for, and have a par value of, $1.00 per unit.

 

Certain of the Class A common units and all of the Class B units contain time- and performance-vesting conditions. Time-vesting units vest ratably over five years subject to certain accelerated vesting based primarily on change of control or certain termination causes. Performance-vesting units will vest, if at all, upon Charlesbank attaining certain investment multiples and internal rates of return in connection with a liquidity event. Both the time- and performance-vesting units require continued employment through any vesting date.  The change in structure and ownership as a result of the IPO did not create a change of control event under the terms of the time- and performance-vesting units.

 

There was no compensation expense incurred for the time- or performance-vesting units as the prices paid for the units were equal to the fair value of the units on the date purchased. Upon an employee’s termination of employment, any unvested incentive units are subject to the Predecessor’s right, but not obligation, to repurchase such units at the employee’s initial acquisition cost (or less in certain circumstances).

 

On August 6, 2009, five members of the Predecessor’s management team purchased, directly or indirectly through Estrella Energy, LP, Class A common units and Class B units along with Charlesbank, for the same value as Charlesbank, ($1.00 per unit). Estrella Energy, LP was partially owned by a non-management third-party, and thus a portion of the time- and performance-based units (“Third-Party Units”) owned by Estrella Energy, LP were owned indirectly by the non-management third-party. On March 20, 2012, Estrella Energy, LP was dissolved and the Predecessor purchased and retired the Third-Party Units for $15.3 million. Management did not receive any consideration in connection with such repurchase.

 

The following table provides information regarding the Predecessor’s outstanding time- and performance-vesting incentive units held by management as of September 30, 2012:

 

 

 

Number of units purchased,
subject to

 

Number of units vested,
subject to

 

 

 

Time

 

Performance

 

Time

 

Performance

 

Class A

 

3,096

 

113,342

 

1,858

 

 

Class B

 

28,639

 

 

17,183

 

 

 

Long Term Incentive Plan

 

As of September 30, 2012, the Predecessor did not have any long term incentive plans or units authorized for issuance under unit-based compensation plans. Subsequent to September 30, 2012 and in connection with the IPO, the Partnership established a long term incentive plan and granted 146,000 phantom units with distribution equivalent rights (See Note 1).

 

Earnings Per Unit

 

The Predecessor has included a calculation for earnings per common unit for all periods presented in which common units were outstanding. The Predecessor calculates earnings per common unit by first deducting the amount of cumulative returns on all classes of redeemable preferred and preferred units from net income and dividing the result by the weighted average number of vested common units. For both periods presented in which common units were outstanding, no unvested common units were included in the computation of the diluted per-unit amount because all would have been anti-dilutive to the net loss per common unit.

 

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Table of Contents

 

9. PREDECESSOR PREFERRED UNITS

 

Preferred Units

 

As of September 30, 2012 and December 31, 2011, the Predecessor’s cumulative preferred units were comprised of 11,850,374 units with a par value of $10 per unit, which accrued value (in the form of additional preferential rights to receive distributions) at a rate of 10% per annum, compounded quarterly.  The cumulative preferred units remain the obligation of the Predecessor and were not conveyed to the Partnership in connection with the IPO.

 

Except in the case of cash distributions made for the purpose of paying federal income taxes, which are made to both preferred and common equity owners in direct proportion to the owners’ respective share of taxable income, owners of the preferred equity receive cash distributions before owners of common equity. The cumulative preferred units and their cumulative return are subordinated to all redeemable preferred units and their cumulative return as discussed below. With the exception of cash distributions for federal income tax purposes, the Credit Agreement included certain covenants that restricted the Predecessor’s ability to pay cash dividends to its owners. The Predecessor adjusts the carrying value of the Preferred Units to reflect the cumulative right to receive distributions on a quarterly basis. As of September 30, 2012 and December 31, 2011, the preferred units’ cumulative right to receive future cash distributions was $43.3 million and $31.8 million, respectively, as a result of the cumulative preferred return on such units.

 

Redeemable Preferred Units

 

On June 10, 2011, in connection with the Predecessor entering into its Credit Agreement, Charlesbank and certain of the Predecessor’s existing investors contributed a total of $15.0 million in exchange for 1.5 million Redeemable Preferred Units. The Redeemable Preferred Units have a par value of $10 per unit and accrue value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. These Redeemable Preferred Units could be redeemed in whole or in part at any time, or would be redeemed by the Predecessor promptly after the satisfaction of all obligations under the Credit Agreement, to the extent of available funds. The Predecessor adjusts the carrying value of the Redeemable Preferred Units to reflect the cumulative right to receive distributions on a quarterly basis. As of September 30, 2012 and December 31, 2011, the right of the Redeemable Preferred Units to receive future cash distributions included an additional $3.9 million and $1.6 million, respectively, as a result of the cumulative preferred return on such units. The Redeemable Preferred Units and their cumulative return remain the obligation of the Predecessor and were not conveyed to the Partnership in connection with the IPO.

 

Series B Redeemable Preferred Units

 

On March 20, 2012, Charlesbank and certain of the Predecessor’s existing investors contributed $25.3 million and an affiliate of Wells Fargo Securities, LLC contributed $10.0 million to the Predecessor in exchange for 2.53 million units and 1.0 million units, respectively, of a new, Series B class, of Redeemable Preferred Units (“Series B Units”). On June 26, 2012, Charlesbank and certain of the Predecessor’s existing investors contributed $7.5 million to the Predecessor in exchange for 0.75 million Series B Units.

 

On September 30, 2012, the Series B Units were comprised of 4.28 million units with a par value of $10 per unit, which accrue value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. The Series B Units could be redeemed by the Predecessor in whole or in part at any time, or would be redeemed by the Predecessor promptly after the satisfaction of all its obligations under the Credit Agreement, to the extent of available funds.  The Series B Units and their cumulative return remain the obligation of the Predecessor and were not conveyed to the Partnership in connection with the IPO.  The Predecessor adjusts the carrying value of the Series B Units to reflect the cumulative right to receive distributions on a quarterly basis. As of September 30, 2012, the Series B Units’ right to receive future cash distributions included $3.8 million as a result of the cumulative preferred return.

 

Series C Redeemable Preferred Units

 

On June 26, 2012, Charlesbank and certain of the Predecessor’s existing investors and other institutional investors contributed $30.0 million to the Predecessor in exchange for 3.0 million units of a new, Series C class, of Redeemable Preferred Units (“Series C Units”). As of September 30, 2012, the Series C Units were comprised of 3.0 million units with a par value of $10 per unit, which accrue value (in the form of an additional preferential right to receive distributions) at a rate of 18% per annum, compounded quarterly. As of September 30, 2012, the Series C Units’ right to receive future cash distributions included $1.4 million as a result of the cumulative preferred return.  The Series C Units and their cumulative return remain the obligation of the Predecessor and were fully redeemed in connection with the IPO (See Note 1).

 

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Table of Contents

 

None of the Preferred Units and Redeemable Preferred Units were conveyed in the IPO, and remain the obligation of the Predecessor. The order of priority of the classes of Redeemable Preferred Units is as follows:

 

·                  Series C Units and their cumulative return are senior to the Series B Units and their cumulative return;

·                  Series B Units and their cumulative return are senior to the Redeemable Preferred Units and their cumulative return; and

·                  Redeemable Preferred Units and their cumulative return are senior to the Preferred Units.

 

Subsequent to September 30, 2012, the Predecessor paid $71.2 million from proceeds related to the IPO and the Over-Allotment Option to the owners of Series B Units and Series C Units for the accumulated 18% priority return on both Series B Units and Series C Units and redeemed all of the outstanding Series C Units and approximately 80% of the outstanding Series B Units.

 

10. CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

 

The Company’s markets are in Texas, Alabama and Mississippi. The Predecessor has a concentration of trade accounts receivable due from customers engaged in the purchase and sale of natural gas and NGL products, and other services. These concentrations of customers may affect our overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. The Company analyzes customers’ historical financial and operational information prior to extending credit.

 

Formosa Hydrocarbons Company, Inc. (“Formosa”) was a significant customer for both the three and nine months ended September 30, 2012 and 2011, respectively. The contract with Formosa expires in 2013 and the Company does not expect to renew the contract. We anticipate that we will have the ability to take the same natural gas volume from our producers and process it at our own facilities, in particular at our new Woodsboro processing facility.

 

During 2011 Sherwin Alumina Company (“Sherwin”) also was a significant customer for both the three and nine month periods ended September 30, 2011.

 

Consolidated revenue attributed to Formosa and Sherwin was as follows (in thousands):

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Formosa

 

$

19,224

 

$

25,607

 

$

85,597

 

$

71,684

 

Sherwin

 

$

14,462

 

$

21,249

 

$

37,280

 

$

63,519

 

 

The Company’s ten largest customers represented 59.0% and 72.8% of consolidated revenue for the three month period ended September 30, 2012 and 2011, respectively. For the nine month periods ended September 30, 2012 and 2011, the Company’s ten largest customers represented 66.0% and 73.5% of consolidated revenue, respectively.

 

The Company did not record a provision for uncollectable accounts receivable as of September 30, 2012 and December 31, 2011.

 

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Table of Contents

 

11. TOTAL REVENUE

 

The Predecessor had revenue consisting of the following categories (in thousands):

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Sales of natural gas

 

$

80,290

 

$

106,609

 

$

217,484

 

$

294,103

 

Sales of NGLs and condensate

 

26,487

 

22,119

 

94,133

 

69,068

 

Transportation, gathering and processing fees

 

11,290

 

7,161

 

32,573

 

19,586

 

Other

 

83

 

72

 

279

 

693

 

Total revenue

 

$

118,150

 

$

135,961

 

$

344,469

 

$

383,450

 

 

12. COMMITMENTS AND CONTINGENCIES

 

Leases

 

The Company has a non-cancelable lease for its office facilities in Dallas, Texas which expires August 16, 2016.  Rent expense related to the lease was as follows (in thousands):

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Rent expense

 

$

75

 

$

75

 

$

229

 

$

200

 

 

Outstanding commitments related to expansion projects

 

During 2011, the Predecessor commenced construction of a new 200 MMcf/d Woodsboro processing plant in Refugio County, Texas. The Predecessor completed construction and commenced operations in July 2012 with capitalized costs of $104.9 million.  In addition, during November 2011, the Predecessor finalized the acquisition of an existing fractionation plant and entered into contracts to refurbish and install this equipment at its Bonnie View site. In July 2012, the Predecessor announced an expansion of the Bonnie View fractionator with a target completion during February 2013.  As of September 30, 2012, the Predecessor had $25.9 million in commitments outstanding for expansion projects.

 

13. RELATED PARTY TRANSACTIONS

 

Charlesbank

 

Charlesbank provided certain management services to the Predecessor under the terms of an agreement (“Charlesbank Agreement”)  which specified an annual management fee of $0.6 million, plus expenses. The Predecessor expensed such services, which are reported within general and administrative expenses; however, the payment of these fees was not allowed under the Predecessor’s Credit Agreement, as amended, for the nine-month period ended September 30, 2012 (See Note 7).  Therefore, no payments under the Charlesbank Agreement were made during the nine months ended September 30, 2012.  Additionally, in connection with the IPO, the Charlesbank Agreement was terminated.  The Predecessor’s management services expense related to the Charlesbank Agreement was as follows (in thousands):

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Management services expense

 

$

218

 

$

150

 

$

518

 

$

450

 

 

Wells Fargo Bank, N.A.

 

The Predecessor entered into the Credit Agreement with a syndicate of financial institutions and other lenders, which included Wells Fargo Bank, N.A., an affiliate of which is a member of the Predecessor’s equity investor group (See Note 7).  Affiliates of

 

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Table of Contents

 

Wells Fargo Bank, N.A. have from time to time engaged in commercial banking and financial advisory transactions with the Predecessor in the normal course of business, including the interest rate swap contract that the Predecessor entered into on March 2, 2012 (See Note 15).

 

Officers

 

On August 6, 2009, an officer of the Predecessor borrowed $150,000 from the Predecessor to fund the acquisition of units of preferred and common equity of the Predecessor pursuant to the terms and conditions of a promissory note executed between the officer and the Predecessor. The balance due to the Predecessor was $25,911 as of December 31, 2011. The note was paid in full on March 16, 2012.

 

14. FAIR VALUE OF FINANCIAL INSTRUMENTS

 

Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Predecessor used the market approach for recurring fair value measurements and to maximize the use of observable inputs and minimize the use of unobservable inputs.

 

The Predecessor categorized the assets or liabilities recorded at fair value based upon the following fair value hierarchy:

 

·                  Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

 

·                  Level 2 valuations use inputs, in the absence of actively quoted market prices that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means.

 

·                  Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. The Predecessor used the most meaningful information available from the market combined with internally developed valuation methodologies to develop the best estimate of fair value.

 

The carrying amount reported in the condensed consolidated balance sheet for cash and cash equivalents, trade accounts receivable and trade accounts payable approximates fair value due to the short maturity of these instruments.

 

The Predecessor determined that the fair value of its debt as of September 30, 2012 and December 31, 2011 approximates book value as there has been no significant change in market conditions or debt pricing affecting the Predecessor.

 

In its normal course of business, the Company periodically enters into month-ahead swap contracts to economically hedge its exposure to certain intra-month natural gas index pricing risk.

 

The current portion of the interest rate swap liability of $0.3 million was included within other current liabilities, and the non-current portion of the interest rate swap liability of $0.4 million was included within other non-current liabilities as of September 30, 2012. The interest rate cap liability was included within other non-current liabilities as of December 31, 2011.

 

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The fair value of the interest rate cap and interest rate swap liabilities were as follows (in thousands):

 

 

 

Fair value measurement as of

 

 

 

September 30,
2012

 

December 31,
2011

 

 

 

Significant Other Observable Inputs
(Level 2)

 

Interest rate cap liability

 

$

 

$

21

 

Interest rate swap liability

 

$

748

 

$

 

 

15. DERIVATIVES

 

In its normal course of business, the Predecessor periodically entered into month-ahead swap contracts to economically hedge its exposure to certain intra-month natural gas index pricing risk. There were no outstanding month-ahead swap contracts as of September 30, 2012 and total volume of month-ahead swap contracts outstanding as of December 31, 2011 was 372,000 MMBtu. The Predecessor defined the contracts as Level 2, as the index price associated with such contracts was observable and tied to the quoted first-of-the-month natural gas index price. The fair value of such contracts was immaterial as of September 30, 2012 and December 31, 2011.

 

The realized gains or losses on these derivatives, reported within Total Revenues were as follows (in thousands):

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Realized gain / (loss) on derivatives

 

$

144

 

$

(13

)

$

105

 

$

83

 

 

On February 17, 2011, the Predecessor entered into an interest rate cap contract with Wells Fargo, N.A., effective March 31, 2011, for $80.0 million in notional value. The contract effectively capped the Predecessor’s LIBOR-based interest rate on that portion of debt on a sliding scale that started at 1.51% as of March 31, 2011 and increased to 4.57% at the end of the contract on June 30, 2014. The notional amount of debt specified in the cap contract declines over time so that the amount of debt covered equated to $65.0 million, $43.0 million and $23.0 million at December 31, 2011, 2012, and 2013, respectively. The Predecessor did not designate the interest rate cap as a hedging instrument for accounting purposes and, thus, the realized and unrealized gains and losses were recognized in interest expense during the period. The Predecessor defined this contract as a fair value hierarchy of Level 2.

 

In March 2012, the Predecessor terminated the interest rate cap and entered into an interest rate swap contract with Wells Fargo, N.A. The interest rate swap has a notional value of $150.0 million, and a maturity date of June 30, 2014. The Predecessor receives a floating rate based upon one-month LIBOR and pays a fixed rate under the interest rate swap of 0.54%.  The Predecessor designated the interest rate swap as a cash flow hedge for accounting purposes 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 is recognized in interest expense immediately. The Predecessor did not have any hedge ineffectiveness during the period ended September 30, 2012. The Predecessor defined this contract as a fair value hierarchy of Level 2.

 

Based on current interest rates, the Predecessor estimated that approximately $0.3 million of hedging activity related to the interest rate swap contract will be reclassified from accumulated other comprehensive income/(loss) into results of operations within the next 12 months.

 

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Table of Contents

 

The amounts recognized in interest expense associated with derivatives that are not designated as hedging instruments were as follows (in thousands):

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,
2012

 

September 30,
2011

 

September 30,
2012

 

September 30,
2011

 

Unrealized gain/(loss) on interest rate cap

 

$

 

$

57

 

$

(222

)

$

(27

)

Realized loss on interest rate cap

 

$

 

$

(49

)

$

 

$

(101

)

 

The amounts recognized in interest expense associated with derivatives that are designated as hedging instruments were as follows (in thousands):

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,
2012

 

September 30,
2011

 

September 30,
2012

 

September 30,
2011

 

(Loss) reclassified from accumulated other comprehensive loss to income/loss
(effective portion)

 

$

(84

)

$

 

$

(169

)

$

 

 

The amount of change in value recognized in other comprehensive income/(loss) on the interest rate swap (effective portion) was as follows (in thousands):

 

 

 

Three months ended

 

Nine months ended

 

 

 

September 30,
2012

 

September 30,
2011

 

September 30,
2012

 

September 30,
2011

 

Change in value recognized in other
comprehensive loss (effective portion)

 

$

(379

)

$

 

$

(728

)

$

 

 

16. PHANTOM UNITS AND EQUITY EQUIVALENT UNITS

 

The Predecessor provided to certain key non-officer employees equity incentive units (‘‘Phantom Units’’) in the Predecessor. The Phantom Units vest upon the occurrence of a change in control where more than 50% of the voting power of the Predecessor changes hands, or upon the occurrence of a liquidity event where, through the sale of some portion of its ownership, the majority owner of the Predecessor achieves or exceeds a targeted rate of return on its original investment. The changes in structure and ownership as a result of the IPO did not create a change of control event under the vesting terms of the Phantom Units.  The number of Phantom Units earned and eligible for vesting increases over a period of years or through the achievement of certain rates of return by the majority owner of the Predecessor or a combination thereof. As of September 30, 2012 and December 31, 2011, no fair value was attributable to the Phantom Units. No compensation expense associated with these units was recorded during the nine months ended September 30, 2012 or September 30, 2011. As of September 30, 2012 and December 31, 2011, the number of authorized and issued Phantom Units was 10,832.

 

On April 1, 2012, the Predecessor granted 15,000 equity equivalent units (‘‘EEUs’’) to a member of management. Each individual EEU is equivalent in economic value to one Class A Common Unit of the Predecessor on a fully diluted basis. The EEUs will vest over a three year period in equal annual installments, and do not represent ownership in the equity of the Predecessor but rather cash incentive compensation and therefore represent liability awards which will be recorded at fair value. The Predecessor believes it is probable that such EEUs will vest, and thus recognized $0.1 million and $0.3 million in compensation expense, reported within general and administrative expense, on such units during the three and nine months ended September 30, 2012.

 

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17. SUBSEQUENT EVENTS

 

Initial Public Offering

 

On November 7, 2012, the Partnership completed its IPO (See Note 1).

 

Subsequent Equity Issuance

 

On November 26, 2012, as contemplated in the IPO, the Partnership’s underwriters exercised in full, their option to purchase 1,350,000 additional common units in the Partnership, at a price of $20.00 per common unit ($18.67 per common unit, net of underwriting discounts and structuring fees), generating net proceeds of approximately $25.2 million. The Partnership then used the net proceeds to purchase 1,350,000 common units in the Partnership from the Predecessor which were redeemed and retired.  The redemption of the Partnership’s common units reduced the Predecessor’s direct ownership in the Partnership from 3,213,713 common units to 1,863,713 common units and increased the common units owned by the public from 9,000,000 common units to 10,350,000 common units.  The Predecessor continues to own all of the subordinated units and all of the general partner units.

 

The Predecessor used a portion of the proceeds from the redemption of common units to pay the accumulated 18% priority return on the outstanding Series B Units which accrued from November 8, 2012 through November 26, 2012 and totaled $313,684. The remaining proceeds of approximately $24.9 million were used to redeem 2,489,081 Series B Units from the owners of the units, resulting in 858,717 Series B Units outstanding as of November 26, 2012.

 

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Table of Contents

 

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

 

You should read the following discussion of the financial condition and results of operations of Southcross Energy Partners, L.P. (the “Partnership”) in conjunction with the unaudited condensed consolidated financial statements and related notes of Southcross Energy LLC and its subsidiaries (the “Predecessor”) that are included herein as well as the historical consolidated financial statements and related notes of the Predecessor in the Partnership’s Rule 424(b)(4) Prospectus filed with the U.S. Securities and Exchange Commission (the “SEC”) on November 2, 2012 (the “Prospectus”). Collectively, the Partnership and the Predecessor are herein referred to as “Company,” “we,” “our” or “us.” Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.

 

Forward-Looking Statements

 

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 herein.

 

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 extent and success of producers replacing declining production and our success in obtaining new sources of natural gas;

·                  the volatility of natural gas and natural gas liquids prices;

·                  our exposure to direct commodity risk may vary over time;

·                  competitive conditions in our industry;

·                  our dependence upon a relatively limited number of customers for a significant portion of our revenues;

·                  the effects of downtime associated with our assets or third parties interconnected with our assets;

·                  our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisitions;

·                  changes in general economic conditions;

·                  actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;

·                  operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

·                  timely receipt of necessary government approvals and permits, our ability to control the costs of construction and other factors that may impact our ability to complete projects within budget and on schedule;

·                  the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;

·                  the effects of existing and future litigation; and

·                  certain factors discussed elsewhere in this report.

 

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of the Partnership’s common units.

 

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

 

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Table of Contents

 

update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

 

Discussion of historical results are for the Predecessor, which contributed all of its ownership in its operating subsidiaries to Southcross Energy Operating, LLC, the Partnership’s operating subsidiary in connection with the Partnership’s initial public offering which closed on November 7, 2012 (the “IPO”).

 

Overview

 

The Partnership is a master limited partnership that provides natural gas gathering, processing, treating, compression and transportation services and NGL fractionation and transportation services for its producer customers. The Partnership also sources, purchases, transports and sells natural gas and NGLs to its power generation, industrial and utility customers. The Partnership’s assets are located in South Texas, Mississippi and Alabama and include three gas processing plants, two fractionation plants and approximately 2,590 miles of pipeline.

 

On September 1, 2011 the Predecessor completed its acquisition of Enterprise Alabama Intrastate, LLC (“EAI”) from Enterprise GTM Holdings L.P., adding to the Company’s gas pipeline assets in Alabama.

 

The Company’s South Texas assets, which operate in or within close proximity to the Eagle Ford shale region, consist of approximately 1,445 miles of pipeline, three natural gas processing plants and two fractionation plants as of September 30, 2012. The Company’s South Texas assets generated 76.7% and 78.1% of revenue for the three and nine months ended September 30, 2012. The Company’s Mississippi and Alabama assets, which consist of approximately 626 and 519 miles of pipeline, respectively, are strategically positioned to provide transportation of natural gas to power generation, industrial and utility customers as well as to unaffiliated interstate pipelines.

 

Recent Developments

 

Initial Public Offering

 

On November 7, 2012, the Partnership completed its IPO.  After the completion of the IPO and the full exercise of the underwriters’ over-allotment option, our Predecessor owns, on behalf of its members, the equity interests in Southcross Energy Partners GP, LLC, the Partnership’s general partner (the “General Partner”), as well as common and subordinated units of the Partnership. The Predecessor’s total direct and indirect equity ownership in the Partnership is 58.5%. The Partnership’s common units are listed on the New York Stock Exchange (NYSE) and are traded under the symbol “SXE.”  The Partnership expects to grow its business and distributable cash flow by expanding the capacity and utilization of its assets and by making selective acquisitions.

 

Factors Affecting Operating Results and Financial Condition

 

During the third quarter of 2012, our Predecessor experienced several factors that negatively impacted its financial performance including (i) the shut-down by the Predecessor’s third-party gas processing service provider of its plant for 34 days, (ii) the curtailment of approximately 518,748 MMBtu of gas processing volumes by the Predecessor’s third-party gas processing service provider and (iii) the failure of certain equipment at the Predecessor’s Gregory facility which restricted gas processing capabilities for a portion of the month of July.  A combination of these factors resulted in a reduction of Adjusted EBITDA by approximately $3.6 million for the three months ended September 30, 2012.

 

How We Evaluate Our Operations

 

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a quarterly basis for consistency and trend analysis. These performance metrics include (i) volume, (ii) gross operating margin, (iii) operations and maintenance expenses, (iv) Adjusted EBITDA and (v) distributable cash flow.

 

Volume — We determine and analyze volumes by operating unit, but report overall volumes after elimination of intercompany deliveries. The volume of natural gas and NGLs on our systems depends on the level of production from natural

 

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Table of Contents

 

gas wells connected to our systems and also from wells connected with other pipeline systems that are interconnected with our systems.

 

Gross Operating Margin — Gross operating margin of our contracts is one of the metrics we use to measure and evaluate our performance. Gross operating margin is not a measure calculated in accordance with accounting principles generally accepted in the United States of America (GAAP). We define gross operating margin as the sum of contract revenues less the cost of natural gas and NGLs sold. For our fixed-fee contracts, we record the fee as revenue and there is no offsetting cost of natural gas and NGLs sold. For our fixed-spread and Percentage of Proceeds (“POP”) arrangements, we record as revenue all of our proceeds from the sale of the natural gas or NGLs and record as an expense the associated cost of natural gas and NGLs sold.

 

Operations and Maintenance Expense — Our management seeks to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, and contract services comprise the most significant portion of our operations and maintenance expense. These expenses are relatively stable and largely independent of volumes delivered through our systems, but may fluctuate depending on the activities performed during a specific period.

 

Adjusted EBITDA and Distributable Cash Flow — We believe that Adjusted EBITDA is a widely accepted financial indicator of our operational performance and ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is not a measure calculated in accordance with GAAP, as it does not include deductions for items such as depreciation, amortization, interest and income taxes, which may be necessary to maintain the business.  We define Adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges and transaction costs that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts and selected gains that are unusual or non-recurring.  Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP.

 

We define distributable cash flow as Adjusted EBITDA plus interest income, less cash paid for interest expense, taxes and maintenance capital expenditures and use distributable cash flow to analyze our performance. Distributable cash flow does not reflect changes in working capital balances.

 

Distributable cash flow is used to assess:

 

·                  the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and

·                  the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

 

Adjusted EBITDA is used as supplemental measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

 

·                  the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·                  the ability of our assets to generate cash sufficient to support the Partnership’s indebtedness and make future cash distributions;

·                  operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

·                  the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

 

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Table of Contents

 

Non-GAAP Financial Measures:

 

Gross operating margin, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations. Net income is the GAAP measure most directly comparable to each of gross operating margin and Adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider any of gross operating margin, Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross operating margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

 

Reconciliations of Non-GAAP financial Measures:

 

The following table presents a reconciliation of gross operating margin to net (loss) income for each of the periods indicated (in thousands):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Reconciliation of Gross Operating Margin to Net (Loss) Income

 

 

 

 

 

 

 

 

 

Gross operating margin

 

$

15,077

 

$

13,472

 

$

55,192

 

$

43,836

 

Add (deduct):

 

 

 

 

 

 

 

 

 

Income tax (expense) benefit

 

7

 

(34

)

(249

)

(200

)

Interest expense

 

(1,362

)

(1,251

)

(4,493

)

(4,053

)

Loss on extinguishment of debt

 

 

 

 

(3,240

)

General and administrative expense

 

(3,351

)

(2,498

)

(8,987

)

(6,725

)

Depreciation and amortization expense

 

(5,522

)

(3,019

)

(12,860

)

(8,621

)

Operations and maintenance expenses

 

(8,890

)

(6,471

)

(24,469

)

(16,764

)

Net (loss) income

 

$

(4,041

)

$

199

 

$

4,134

 

$

4,233

 

 

The following table presents a reconciliation of net cash flows provided by operating activities to net income and Adjusted EBITDA and for each of the periods indicated (in thousands):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Reconciliation of Net Cash Flows Provided by Operating Activities to Net Income and Adjusted EBITDA

 

 

 

 

 

 

 

 

 

Net cash flows provided by operating activities

 

$

2,818

 

$

1,443

 

$

15,062

 

$

12,003

 

Add (deduct):

 

 

 

 

 

 

 

 

 

Depreciation and amortization expense

 

(5,522

)

(3,019

)

(12,860

)

(8,621

)

Compensation expense under accrued liability awards

 

(146

)

 

(293

)

 

Loss on extinguishment of debt

 

 

 

 

(3,240

)

Deferred financing fees amortization

 

(322

)

(173

)

(948

)

(713

)

Gain on sales of plant, property and equipment

 

 

 

 

522

 

Unrealized derivatives gain (loss)

 

 

57

 

(222

)

(27

)

Realized gains on cash flow hedge

 

 

 

 

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

Accounts receivable

 

13,064

 

3,305

 

2,292

 

1,942

 

Accrued sales

 

 

 

 

 

Prepaid expenses and other

 

815

 

405

 

198

 

141

 

Other non-current assets

 

407

 

1,448

 

1,598

 

1,620

 

Accounts payable

 

(12,901

)

(1,717

)

166

 

(204

)

Accrued cost of sales

 

 

 

 

 

Interest payable

 

(76

)

208

 

(75

)

1,779

 

Accrued expenses and other liabilities

 

(2,178

)

(1,758

)

(784

)

(969

)

Net (loss) income

 

$

(4,041

)

$

199

 

$

4,134

 

$

4,233

 

Add (deduct):

 

 

 

 

 

 

 

 

 

Depreciation and amortization expense

 

5,522

 

3,019

 

12,860

 

8,621

 

Interest expense

 

1,362

 

1,251

 

4,493

 

4,053

 

Unrealized derivatives (gain) loss

 

 

(57

)

222

 

27

 

Loss on extinguishment of debt

 

 

 

 

3,240

 

Compensation expense under accrued liability awards

 

147

 

 

293

 

 

Income tax (benefit) expense

 

(7

)

34

 

249

 

200

 

Adjusted EBITDA

 

$

2,983

 

$

4,446

 

$

22,251

 

$

20,374

 

 

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Table of Contents

 

Predecessor Results of Operations

 

Predecessor Three and Nine Months Ended September 30, 2012 Compared to Three and Nine Months Ended September 30, 2011

 

The following table summarizes the Predecessor’s results of operations (in thousands, except operating data):

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

Total Revenue

 

$

118,150

 

$

135,961

 

$

344,469

 

$

383,450

 

Expenses:

 

 

 

 

 

 

 

 

 

Cost of natural gas and liquids sold

 

103,073

 

122,489

 

289,277

 

339,614

 

Operations and maintenance

 

8,890

 

6,471

 

24,469

 

16,764

 

Depreciation and amortization

 

5,522

 

3,019

 

12,860

 

8,621

 

General and administrative

 

3,351

 

2,498

 

8,987

 

6,725

 

Total expenses

 

$

120,836

 

$

134,477

 

$

335,593

 

$

371,724

 

 

 

 

 

 

 

 

 

 

 

Income from operations

 

(2,686

)

1,484

 

8,876

 

11,726

 

Loss on extinguishment of debt

 

 

 

 

3,240

 

Interest expense

 

1,362

 

1,251

 

4,493

 

4,053

 

Income tax (benefit) expense

 

(7

)

34

 

249

 

200

 

Net (loss) income

 

$

(4,041

)

$

199

 

$

4,134

 

$

4,233

 

 

 

 

 

 

 

 

 

 

 

Other Financial Data:

 

 

 

 

 

 

 

 

 

Adjusted EBITDA

 

$

2,983

 

$

4,446

 

$

22,251

 

$

20,374

 

Gross operating margin

 

$

15,077

 

$

13,472

 

$

55,192

 

$

43,836

 

Maintenance capital expenditures

 

$

1,047

 

$

1,238

 

$

2,784

 

$

2,966

 

Expansion capital expenditures

 

$

39,799

 

$

58,829

 

$

109,666

 

$

94,983

 

 

 

 

 

 

 

 

 

 

 

Operating data:

 

 

 

 

 

 

 

 

 

Average throughput of gas (MMBtu/d)

 

538,991

 

504,170

 

551,352

 

454,193

 

Average volume of processed gas (MMBtud/d)

 

166,140

 

116,605

 

179,590

 

112,084

 

Average volumes of NGLs delivered (Mgal/d)

 

350.1

 

174.3

 

368.5

 

196.1

 

Realized prices on natural gas volumes sold/Btu ($/MMBtu)

 

$

2.89

 

$

4.26

 

$

2.62

 

$

4.26

 

Realized prices on NGL volumes sold/gal ($/gal)

 

$

0.82

 

$

1.38

 

$

0.93

 

$

1.29

 

 

Predecessor Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

 

Volume and overview.  Our Predecessor’s average volume of natural gas per day increased 6.9% to 538,991 MMBtu/d during the three months ended September 30, 2012, compared to 504,170 MMBtu/d during the three months ended September 30, 2011. Processed gas volumes increased 42.5% to 166,140 MMBtu/d during the three months ended September 30, 2012, compared to 116,605 MMBtu/d during the three months ended September 30, 2011, reflecting the increase in rich gas volumes processed at our facilities that began entering our system in September 2011.

 

The average volume of NGLs produced for the three months ended September 30, 2012 was 350.1 Mgal/d, an increase of 101.0%, compared to 174.3 Mgal/d for the three months ended September 30, 2011. This increase was due to the impact of increased volumes of rich gas processed at our facilities.

 

Gross operating margin, for the three months ended September 30, 2012, increased to $15.1 million, compared to $13.5 million for the three months ended September 30, 2011.  This increase of 11.9% was due primarily to the higher processing and gathering fees for Eagle Ford area rich gas volumes on our systems, offset by (i) the negative effects of a shut-down of our third-party processing service provider’s plant for 34 days, (ii) the curtailment of gas processing volumes below our contractually guaranteed amounts by our third-party gas processing service provider for most of the month of September and (iii) the failure of

 

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certain equipment at our Gregory facility which restricted the gas processing capabilities for a portion of the month of July.  We estimate that Adjusted EBITDA for the three months ended September 30, 2012 was impacted negatively by approximately $3.6 million because of these events.  Adjusted EBITDA decreased by 34.4% to $3.0 million for the three months ended September 30, 2012, compared to $4.5 million for the three months ended September 30, 2011, primarily due to the negative effects of the challenges mentioned above, coupled with higher operations and maintenance expenses and higher general and administrative expenses partially offset by revenues from higher volumes.  A net loss of $4.0 million for the three months ended September 30, 2012 compared to $0.2 million of net income for the three months ended September 30, 2011. The decline in net income was for the same reasons stated above as well as higher depreciation and amortization expense and increased interest expense.

 

Revenue.  Our Predecessor’s total revenue for the three months ended September 30, 2012 was $118.1 million, compared to $135.9 million for the three months ended September 30, 2011.  This decrease of $17.8 million, or 13.1%, was due primarily to the impact of lower natural gas prices upon natural gas sales contracts.  Results for the three months ended September 30, 2012 also included increased revenues related to the EAI acquisition, which contributed $6.0 million in revenue in the three months ended September 30, 2012 compared to $2.4 million in the same period of 2011.  Sales of NGLs and condensate increased 19.8%, reflecting the benefit of new volumes delivered to our processing plants, partially offset by lower NGL prices.  Realized average natural gas and NGL prices were as follows:

 

 

 

Three months ended September 30,

 

 

 

2012

 

2011

 

Natural Gas

 

$2.89/MMBtu

 

$4.26/MMBtu

 

NGL

 

$0.82/gal

 

$1.38/gal

 

 

Cost of natural gas and NGLs sold.  Our Predecessor’s cost of natural gas and NGLs sold for the three months ended September 30, 2012 was $103.1 million, compared to $122.5 million for the three months ended September 30, 2011. This decline of $19.4 million, or 15.8%, was due to the effect of lower natural gas and NGL prices more than offsetting the higher volume of NGL sales. The results for the three months ended September 30, 2012 included three months of throughput from the EAI acquisition, versus one month for the three months ended September 30, 2011.

 

Operations and maintenance expense.  Operations and maintenance expense for the three months ended September 30, 2012 was $8.9 million, compared to $6.5 million for the three months ended September 30, 2011. This increase of $2.4 million, or 36.9%, was due primarily to additional costs of operating the Woodsboro processing plant, and additional costs at the Gregory plant which processed more gas in the three months ended September 30, 2012 than in the same period ended September 30, 2011, increased ad valorem and other taxes due to investments and expansion of our asset values, and higher labor and benefit costs due to increased staffing to support our expansion.

 

General and administrative (‘‘G&A’’) expenses.  G&A expenses for the three months ended September 30, 2012 were $3.4 million, compared to $2.5 million for the three months ended September 30, 2011. This increase of $0.9 million, or 36.0%, was due primarily to increased employment-related expenses and support costs as we continued to build our corporate and support infrastructure.

 

Depreciation and amortization expense.  Depreciation and amortization expense for the three months ended September 30, 2012 was $5.5 million, compared to $3.0 million for the three months ended September 30, 2011.  The increase of $2.5 million, or 83.3%, was due primarily to the EAI acquisition and the growth capital expenditures made during the second half of 2011 and the first nine months of 2012.

 

Interest expense.  For the three months ended September 30, 2012, net interest expense was $1.4 million, compared to $1.3 million for the three months ended September 30, 2011. This increase was due to higher average borrowings compared to the same period in 2011.

 

Predecessor Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

 

Volume and overview.  Our Predecessor’s average volume of natural gas increased by 21.4% to 551,352 MMBtu/d for the nine months ended September 30, 2012, compared to 454,193 MMBtu/d for the nine months ended September 30, 2011. This increase was due primarily to the increase in rich gas volumes entering our pipelines from the Eagle Ford Shale area beginning in September 2011 that was processed at our facilities.

 

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Processed gas volumes increased 60.2% to 179,590 MMBtu/d during the nine months ended September 30, 2012, compared to 112,084 MMBtu/d during the nine months ended September 30, 2011, reflecting the increase in rich gas volumes that began entering our system in September 2011.

 

The average volume of NGLs produced for the nine months ended September 30, 2012 was 368.5 Mgal/d, compared to 196.1 Mgal/d for 2011, an increase of 87.9%. This increase was due primarily to the increase in rich gas volumes entering our pipelines from the Eagle Ford Shale area beginning in September 2011 that was processed at our facilities.

 

Gross operating margin for the nine months ended September 30, 2012 improved to $55.2 million compared to $43.8 million for the same period in 2011, an increase of 26.0%, primarily as a result of higher processing fees, gathering fees and NGL margin, and the benefit of eight additional months of operations from the acquisition of EAI, all of which more than offset the negative effects of the operational challenges created by processing plant outages and curtailments of processed volumes occurring primarily during the third quarter of 2012. We estimate that Adjusted EBITDA for the nine months ended September 30, 2012 was impacted negatively by approximately $4.4 million as a result of (i) a shut-down of our third-party processing service provider’s plant for 34 days, (ii) the curtailment of gas processing volumes below our contractually-guaranteed amounts by our third-party gas processing service provider for most of the month of September and (iii) the failure of certain equipment at our Gregory facility for a portion of the months of June and July which restricted gas processing capabilities during such time.  Adjusted EBITDA increased by 9.3% to $22.3 million for the nine months ended September 30, 2012 compared to $20.4 million for the same period in 2011, due primarily to the improvement in gross operating margin, offset by the negative effects of the operational challenges mentioned above and by higher operations and maintenance expense and increased G&A expenses.  Net income for the nine months ended September 30, 2012 of $4.1 million was comparable to net income of $4.2 million for the same period in 2011.

 

Revenue.  Our Predecessor’s total revenue for the nine months ended September 2012 was $344.5 million, compared to $383.5 million for the same period in 2011. This decrease of $39.0 million, or 10.2%, was due primarily to lower natural gas prices and lower NGL prices offset by higher NGL sales volumes and the inclusion of nine months of results from the EAI acquisition, which contributed an incremental $15.8 million in the nine months ended September 30, 2012 compared to the prior year period. We realized average natural gas and NGL prices as follows:

 

 

 

Nine months ended September 30,

 

 

 

2012

 

2011

 

Natural Gas

 

$2.61/MMBtu

 

$4.26/MMBtu

 

NGL

 

$0.93/gal

 

$1.29/gal

 

 

Cost of natural gas and NGLs sold.  Our Predecessor’s cost of natural gas and NGLs sold for the nine months ended September 30, 2012 was $289.3 million compared to $339.6 million for the same period in 2011. This decrease of $50.3 million, or 14.8%, was due primarily to lower prices of natural gas and NGLs, offset by the cost of increased NGL volumes and, in part, by the inclusion of nine months of throughput from the EAI acquisition.

 

Operations and maintenance expense.  Operating and maintenance expense for the nine months ended September 30, 2012 was $24.5 million compared to $16.8 million for the same period in 2011. This increase of $7.7 million, or 45.8%, was due primarily to the inclusion of nine months of expenses relating to the operation of the pipeline and gathering system in connection with the EAI acquisition, as well as additional pipeline integrity costs, the start-up and operation of the Woodsboro processing plant and additional costs at the Gregory plant which processed more gas in the nine months ended September 30, 2012 than in the same period ended September 30, 2011.

 

General and administrative expenses.  G&A expenses for the nine months ended September 30, 2012, were $9.0 million compared to $6.7 million for the same period in 2011. This increase of $2.3 million, or 34.3%, was due primarily to increased employment-related expenses as we continued to build our corporate and support infrastructure.

 

Depreciation and amortization expense.  Depreciation and amortization expense for the nine months ended September 30, 2012 was $12.9 million compared to $8.6 million for the same period in 2011.  The increase was primarily as a result of the EAI acquisition and growth capital expenditures made during the second half of 2011 and the first nine months 2012.

 

Loss on extinguishment of debt.  For the nine months ended September 30, 2011, our Predecessor recorded a loss on the extinguishment of debt of $3.2 million relating to the write-off of previously deferred financing fees as a result of entering into a new credit agreement on June 10, 2011.  No such losses occurred during the nine months ended September 30, 2012.

 

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Interest expense.  Our Predecessor’s interest expense for the nine months ended September 30, 2012 was $4.5 million, compared to $4.1 million for the same period in 2011. Our Predecessor’s average effective interest rate was 3.85% and 3.64% for the nine months ended September 30, 2012 and 2011, respectively.

 

Predecessor Cash Flows

 

Operating cash flows.  Net cash provided by operating activities was $15.1 million for the nine months ended September 30, 2012 compared to $12.0 million for the nine months ended September 30, 2011. The increase in cash provided by operating activities of $3.1 million was attributable to increases in gross operating margin offset by higher operations and maintenance costs.

 

Investing cash flows.  Net cash used in investing activities was $112.5 million and $97.4 million for the nine months ended September 30, 2012 and 2011, respectively.  The increase in cash used in investing activities of $15.1 million was related primarily to increases in expansion capital expenditures associated with our growth activities.

 

Financing cash flows.  Net cash provided by financing activities was $99.9 million for the nine months ended September 30, 2012, compared to $65.1 million for the nine months ended September 30, 2011. The increase in cash provided by financing activities of $34.8 million was attributable primarily to an increase in capital contributions totaling $57.8 million, offset by a payment of $15.3 million to retire the equity of a non-management unitholder and a net decrease in borrowings of $7.7 million.

 

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Liquidity and Capital Resources

 

Sources of liquidity.  Cash generated from operations, investments by Charlesbank and other inverstors, and borrowings under our Predecessor’s Amended and Restated Credit Agreement dated June 10, 2011, (the “Credit Agreement”) have been our Predecessor’s primary sources of historical liquidity. Our Predecessor’s primary cash requirements consisted of operating and G&A expenses, capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt and acquisitions of new assets or businesses.

 

The Partnership expects to fund short term cash requirements, such as operating and G&A expenses and maintenance capital expenditures to sustain existing operations, primarily through operating cash flows. We expect to fund long term cash requirements, such as for expansion projects and acquisitions, through several sources, including operating cash flows, borrowings under the Partnership’s senior secured credit facility (the “Senior Secured Credit Facility”) and issuances of additional equity and debt securities, as appropriate and subject to market conditions.

 

For additional discussion, please read the Prospectus.

 

Capital resources.  The Partnership’s business is capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our Predecessor’s capital requirements have consisted primarily of, and we anticipate the Partnership’s capital requirements will continue to be:

 

·                  maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and

·                  expansion capital expenditures, which are capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition.

 

During the nine months ended September 30, 2012, capital expenditures totaled $112.5 million, consisting of $2.8 million of maintenance capital and $109.7 million of expansion capital. Our Predecessor used funds from operations, equity contributions and borrowings under its Credit Agreement to fund those capital expenditures. The expansion capital expenditures related mainly to (i) a new 200 MMcf/d Woodsboro processing plant in Refugio County, Texas and (ii) the refurbishment and installation of fractionation equipment at our Bonnie View site.

 

Outlook.  Cash flow is affected by a number of factors, some of which we cannot control.  These factors include prices and demand for our services, operational risks, volatility in commodity prices or interest rates, industry and economic conditions, conditions in the financial markets, and other factors.

 

Recent commodity prices and financial market conditions have supported significant opportunities for volume growth from shale resource plays.  The Partnership’s ability to benefit from growth projects to accommodate strong drilling activity is subject to operational risks and uncertainties such as the uncertainty inherent in some of the assumptions underlying design specifications for new, modified or expanded facilities. These risks also impact third-party service providers and their facilities. Delays or underperformance of our facilities or third-party facilities may adversely affect our ability to generate cash from operations and comply with our obligations, including the covenants under our debt instruments.  In other cases, actual production delivered may fall below volume estimates that we relied upon in deciding to pursue an acquisition or other growth project.  Future cash flow and the Partnership’s ability to comply with its debt covenants would likewise be affected adversely if we experienced declining volumes overall over a sustained period in combination with unfavorable commodity prices.

 

Our Predecessor’s historical financing strategy for funding long term capital expenditures has been to target a roughly equal mix of debt and equity financing and a consolidated leverage ratio which complied with the Predecessor’s credit agreement covenants.  If the Partnership exceeds its target leverage ratio, as we expect it will from time to time for significant capital projects, acquisitions or other investments, we anticipate reducing leverage through growth in cash flow or the issuance of additional equity.

 

Our Predecessor’s net long term debt increased by $44.9 million during the nine months ended September 30, 2012, mainly due to its capital expansion projects.

 

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In connection with the IPO, debt outstanding under the Partnership’s $350.0 million Senior Secured Credit Facility was initially funded at $150.0 million, $103.0 million lower than our Predecessor’s September 30, 2012 debt balance.

 

We believe that cash from operations, cash on hand and the Partnership’s Senior Secured Credit Facility will provide sufficient liquidity to meet future short term capital requirements and to fund committed capital expenditures for the remainder of 2012 and 2013.

 

Organic expansion projects and acquisitions are key elements of our business strategy. We intend to finance the Partnership’s growth capital primarily through the issuance of debt and equity. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate larger acquisitions or capital projects, we will require access to additional capital.  The Partnership’s access to capital over the longer term will depend on its future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets and other financial and business factors, many of which are beyond our control.

 

Our Indebtedness

 

As of September 30, 2012, our Predecessor’s aggregate outstanding indebtedness totaled $253.2 million, and the Predecessor was in compliance with the financial covenants under its debt agreements.

 

Off-Balance Sheet Arrangements

 

Our Predecessor had no off-balance sheet arrangements during the nine months ended September 30, 2012.

 

Recent Accounting Pronouncements

 

For information on new accounting pronouncements see Note 2, “Summary of Significant Accounting Policies”, included in Item 1 of this report.

 

Critical Accounting Policies and Estimates

 

Our Predecessor’s significant accounting policies are described in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of the Prospectus.  The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no changes to the Predecessor’s significant accounting policies.

 

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Table of Contents

 

Item 3. Quantitative and Qualitative Disclosures about Market Risk

 

Commodity Price Risk.

 

The Company is exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate. Both profitability and cash flow are affected by volatility in the prices of these commodities. Natural gas and NGL prices are impacted by changes in the supply and demand for natural gas and NGLs, as well as market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors” in Item 1A of Part II of this report.  Adverse effects on cash flow from reductions in natural gas and NGL product prices could adversely affect the Partnership’s ability to make distributions to unitholders.  We manage this commodity price exposure through an integrated strategy that includes management of the commercial terms of our contract portfolio by entering into fixed fee-based or fixed-spread arrangements whenever possible and the use of swing swaps.  Swing swaps are generally short term in nature (one month) and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. Neither our Predecessor nor the Partnership have entered into any long term derivative contracts to manage exposure to commodity price risk. Natural gas prices, however, also can affect profitability indirectly by influencing the level of drilling activity in our areas of operation.  We are a net seller of NGLs and, as such, financial results also are exposed to fluctuations in NGL pricing.

 

Interest Rate Risk

 

We have exposure to changes in interest rates on indebtedness.  In March 2012, our Predecessor entered into an interest rate swap contract for $150.0 million notional amount of debt. The contract, which was transferred to the Partnership in conjunction with the IPO, effectively caps the Partnership’s LIBOR based interest rate exposure on $150 million of debt at 0.54% through June 30, 2014.

 

The credit markets have recently experienced historical lows in interest rates. As the overall economy strengthens, it is possible that monetary policy will tighten, resulting in higher interest rates. Interest rates on floating rate credit facilities and future debt offerings could be higher than current levels, causing the Partnership’s financing costs to increase accordingly.

 

A hypothetical increase or decrease in interest rates by 1.0% would have changed our Predecessor’s interest expense by $0.6 million for the nine months ended September 30, 2012.

 

Impact of Seasonality

 

The results of operations are not affected materially by seasonality.

 

Item 4.  Controls and Procedures.

 

Disclosure controls.  The Chief Executive Officer and Chief Financial Officer of the General Partner, which is responsible for the management of the Partnership, have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of the end of the period covered by this quarterly report (the “Evaluation Date”). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of the General Partner have concluded that, as of the Evaluation Date, the Partnership’s disclosure controls and procedures are effective.

 

Internal control over financial reporting.  There have been no changes in internal controls over financial reporting (as defined in Rule 13(a)—15(f) or Rule 15d—15(f) of the Exchange Act) during the third fiscal quarter of 2012 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

 

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Table of Contents

 

PART II — OTHER INFORMATION

 

Item 1.  Legal Proceedings

 

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.

 

Item 1A. Risk Factors

 

The Risk Factors contained in the Southcross Energy Partners, L.P. (the “Partnership”) Rule 424(b)(4) Prospectus (the “Prospectus”) filed with the Securities and Exchange Commission on November 2, 2012, which were set forth under the section entitled “Risk Factors”, are incorporated herein by reference.  There has been no material change in our risk factors from those described in the Prospectus.

 

These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

On November 2, 2012, the Partnership priced an initial public offering of 9,000,000 common units at a price to the public of $20 per unit ($18.75 per common unit, net of underwriting discounts) (the “IPO”). The IPO was made pursuant to a registration statement on Form S-1 originally filed on April 20, 2012, as amended through October 22, 2012 (Registration No. 333-180841) that was declared effective by the SEC on November 2, 2012. On November 26, 2012, the underwriters exercised in full their option to purchase an additional 1,350,000 common units (the “Over-Allotment Option”). Citigroup Global Markets Inc., Wells Fargo Securities, LLC, Barclays Capital Inc. and JP Morgan Securities LLC acted as joint book-running managers for the IPO. RBC Capital Markets, LLC, Raymond James and Associates, Inc., Robert W. Baird & Co. Incorporated, Stifel, Nicolaus & Company, Incorporated and Suntrust Robinson Humphrey, Inc. acted as co-managers for the IPO.

 

The IPO closed on November 7, 2012. The Partnership received net proceeds (after deducting underwriting discounts, commissions and a structuring fee) from the IPO of approximately $168.0 million. The Partnership used the proceeds to:

 

·                  repay $129.5 million of indebtedness under a credit agreement assumed from Southcross Energy LLC, the Partnership’s predecessor (the “Predecessor”); and

·                  make cash distributions to the Predecessor of $38.5 million.

 

The Partnership used the $25.2 million it received in connection with underwriters’ exercising the Over-Allotment Option to purchase and retire 1,350,000 common units from the Predecessor.

 

In connection with the closing of the IPO, we issued to the Predecessor an aggregate of 3,213,713 common units and 12,213,713 subordinated units in exchange for a contribution to the Partnership by the Predecessor of its remaining limited liability company interests in Southcross Energy Operating, LLC (“Southcross Operating”).  The Predecessor also owns all of the interest in the Partnership’s general partner who holds a 2% economic interest in the Partnership (the general partner conveyed its interest in Southcross Operating to us in exchange for 498,519 general partner units).  These issuances were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

 

Item 3. Defaults upon Senior Securities

 

Not applicable.

 

Item 4. Mine Safety Disclosures

 

Not applicable.

 

Item 5. Other Information

 

Not applicable.

 

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Item 6. Exhibits

 

Exhibit

 

 

Number

 

Description

 

 

 

3.1

 

Certificate of Limited Partnership of Southcross Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).

3.2

 

First Amended and Restated Agreement of Limited Partnership of Southcross Energy Partners, L.P., dated as of November 7, 2012 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K dated November 7, 2012).

3.3

 

Certificate of Formation of Southcross Energy Partners GP, LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-180841)).

3.4

 

Amended and Restated Limited Liability Company Agreement of Southcross Energy Partners GP, LLC, dated as of November 7, 2012 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K dated November 7, 2012).

31.1

 

Certification of Chief Executive Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

 

Certification of Chief Financial Officer, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

 

Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

SOUTHCROSS ENERGY PARTNERS, L.P.

 

 

 

 

By: Southcross Energy Partners GP, LLC, its general partner

 

 

 

 

 

 

Date: December 13, 2012

By:

/s/ J. Michael Anderson

 

 

J. Michael Anderson

 

 

Senior Vice President and Chief Financial Officer

 

 

Principal Financial Officer

 

 

 

Date: December 13, 2012

By:

/s/ David M. Mueller

 

 

David M. Mueller

 

 

Senior Vice President and Chief Accounting Officer

 

 

Principal Accounting Officer

 

37