XNAS:XTEX Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

 

x           Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

for the quarterly period ended March 31, 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: 000-50067

 

CROSSTEX ENERGY, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

16-1616605

(State of organization)

 

(I.R.S. Employer Identification No.)

 

 

 

2501 CEDAR SPRINGS

 

 

DALLAS, TEXAS

 

75201

(Address of principal executive offices)

 

(Zip Code)

 

(214) 953-9500

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether 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 x No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) 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 x

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o No x

 

As of April 24, 2012, the Registrant had 50,869,997 common units outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

Item

 

Description

 

Page

 

 

 

 

 

 

 

PART I—FINANCIAL INFORMATION

 

 

 

 

 

 

 

1.

 

Financial Statements

 

3

 

 

 

 

 

2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

22

 

 

 

 

 

3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

30

 

 

 

 

 

4.

 

Controls and Procedures

 

33

 

 

 

 

 

 

 

PART II—OTHER INFORMATION

 

 

 

 

 

 

 

1.

 

Legal Proceedings

 

33

 

 

 

 

 

1A.

 

Risk Factors

 

33

 

 

 

 

 

6.

 

Exhibits

 

35

 



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Condensed Consolidated Balance Sheets

 

 

 

March 31,

 

December 31,

 

 

 

2012

 

2011

 

 

 

(Unaudited)

 

 

 

 

 

(In thousands)

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

20,630

 

$

24,143

 

Accounts receivable:

 

 

 

 

 

Trade, net of allowance for bad debt of $210 and $405, respectively

 

12,352

 

22,680

 

Accrued revenue and other

 

118,623

 

143,115

 

Fair value of derivative assets

 

1,274

 

2,867

 

Natural gas and natural gas liquids, prepaid expenses and other

 

16,338

 

9,951

 

Total current assets

 

169,217

 

202,756

 

Property and equipment, net of accumulated depreciation of $425,708 and $406,273, respectively

 

1,251,304

 

1,241,901

 

Fair value of derivative assets

 

131

 

 

Intangible assets, net of accumulated amortization of $211,975 and $199,248, respectively

 

438,734

 

451,462

 

Investment in limited liability company

 

39,860

 

35,000

 

Other assets, net

 

24,204

 

24,212

 

Total assets

 

$

1,923,450

 

$

1,955,331

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable, drafts payable and other

 

$

16,389

 

$

22,550

 

Accrued gas purchases

 

80,203

 

106,232

 

Fair value of derivative liabilities

 

4,843

 

5,587

 

Other current liabilities

 

46,828

 

66,065

 

Accrued interest

 

8,991

 

24,918

 

Total current liabilities

 

157,254

 

225,352

 

Long-term debt

 

852,883

 

798,409

 

Other long-term liabilities

 

23,156

 

23,919

 

Deferred tax liability

 

7,067

 

7,192

 

Fair value of derivative liabilities

 

110

 

 

Commitments and contingencies

 

 

 

Partners’ equity

 

882,980

 

900,459

 

Total liabilities and partners’ equity

 

$

1,923,450

 

$

1,955,331

 

 

See accompanying notes to condensed consolidated financial statements.

 

3



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Condensed Consolidated Statements of Operations

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

(Unaudited)

 

 

 

(In thousands, except per unit amounts)

 

Revenues

 

$

371,709

 

$

489,770

 

Operating costs and expenses:

 

 

 

 

 

Purchased gas and NGLs

 

271,956

 

399,933

 

Operating expenses

 

27,806

 

25,044

 

General and administrative

 

14,963

 

11,755

 

Gain on sale of property

 

(98

)

(19

)

Loss on derivatives

 

2,169

 

3,421

 

Depreciation and amortization

 

32,178

 

29,653

 

Total operating costs and expenses

 

348,974

 

469,787

 

Operating income

 

22,735

 

19,983

 

Other income (expense):

 

 

 

 

 

Interest expense, net of interest income

 

(19,382

)

(19,769

)

Other income

 

12

 

113

 

Total other expense

 

(19,370

)

(19,656

)

Income before non-controlling interest and income taxes

 

3,365

 

327

 

Income tax provision

 

(424

)

(253

)

Net income

 

2,941

 

74

 

Less: Net loss attributable to the non-controlling interest

 

(38

)

(54

)

Net income attributable to Crosstex Energy, L.P.

 

$

2,979

 

$

128

 

Preferred interest in net income attributable to Crosstex Energy, L.P.

 

$

4,853

 

$

4,265

 

General partner interest in net income

 

$

(71

)

$

(522

)

Limited partners’ interest in net income attributable to Crosstex Energy, L.P.

 

$

(1,803

)

$

(3,615

)

Net loss attributable to Crosstex Energy, L.P. per limited partners’ unit:

 

 

 

 

 

Basic and diluted common unit

 

$

(0.03

)

$

(0.07

)

 

See accompanying notes to condensed consolidated financial statements.

 

4



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Consolidated Statements of Comprehensive Income (Loss)

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Net income

 

$

2,941

 

$

74

 

Hedging losses reclassified to earnings

 

354

 

388

 

Adjustment in fair value of derivatives

 

(39

)

(1,397

)

Comprehensive income (loss)

 

3,256

 

(935

)

Comprehensive loss attributable to non-controlling interest

 

38

 

54

 

Comprehensive income (loss) attributable to Crosstex Energy, L.P.

 

$

3,294

 

$

(881

)

 

See accompanying notes to condensed consolidated financial statements.

 

5



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Consolidated Statements of Changes in Partners’ Equity

Three Months Ended March 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General Partner

 

Other

 

 

 

 

 

 

 

Common Units

 

Preferred Units

 

Interest

 

Comprehensive

 

Non-Controlling

 

 

 

 

 

$

 

Units

 

$

 

Units

 

$

 

Units

 

Income (loss)

 

Interest

 

Total

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, December 31, 2011

 

$

730,010

 

50,677

 

$

147,770

 

14,706

 

$

20,322

 

1,334

 

$

(503

)

$

2,860

 

$

900,459

 

Proceeds from exercise of unit options

 

178

 

35

 

 

 

 

 

 

 

178

 

Conversion of restricted units for common units, net of units withheld for taxes

 

(980

)

156

 

 

 

 

 

 

 

(980

)

Capital contributions

 

 

 

 

 

80

 

4

 

 

 

80

 

Stock-based compensation

 

1,338

 

 

 

 

1,160

 

 

 

 

2,498

 

Distributions

 

(16,584

)

 

(4,706

)

 

(1,221

)

 

 

 

(22,511

)

Net income (loss)

 

(1,803

)

 

4,853

 

 

(71

)

 

 

(38

)

2,941

 

Hedging gains or losses reclassified to earnings

 

 

 

 

 

 

 

354

 

 

354

 

Adjustment in fair value of derivatives

 

 

 

 

 

 

 

(39

)

 

(39

)

Balance, March 31, 2012

 

$

712,159

 

50,868

 

$

147,917

 

14,706

 

$

20,270

 

1,338

 

$

(188

)

$

2,822

 

$

882,980

 

 

See accompanying notes to condensed consolidated financial statements.

 

6



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Consolidated Statements of Cash Flows

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

2,941

 

$

74

 

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

 

 

 

 

 

Depreciation and amortization

 

32,178

 

29,653

 

Gain on sale of property

 

(98

)

(19

)

Deferred tax benefit

 

(125

)

(125

)

Non-cash stock-based compensation

 

2,498

 

2,190

 

Non-cash portion of derivatives loss

 

1,143

 

1,574

 

Amortization of debt issue costs

 

1,247

 

1,552

 

Amortization of discount on notes

 

474

 

474

 

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable, accrued revenue and other

 

34,821

 

2,793

 

Natural gas and natural gas liquids, prepaid expenses and other

 

(5,817

)

(1,547

)

Accounts payable, accrued gas purchases and other accrued liabilities

 

(57,881

)

(34,799

)

Net cash provided by operating activities

 

11,381

 

1,820

 

Cash flows from investing activities:

 

 

 

 

 

Additions to property and equipment

 

(36,269

)

(21,596

)

Proceeds from sale of property

 

121

 

47

 

Investment in limited liability company

 

(4,860

)

 

Net cash used in investing activities

 

(41,008

)

(21,549

)

Cash flows from financing activities:

 

 

 

 

 

Proceeds from borrowings

 

169,000

 

84,250

 

Payments on borrowings

 

(115,000

)

(68,250

)

Payments on capital lease obligations

 

(762

)

(723

)

Increase (decrease) in drafts payable

 

(2,651

)

6,302

 

Debt refinancing costs

 

(1,240

)

(106

)

Conversion of restricted units, net of units withheld for taxes

 

(980

)

(1,328

)

Distribution to partners

 

(22,511

)

(17,597

)

Proceeds from exercise of unit options

 

178

 

224

 

Contributions from general partner

 

80

 

97

 

Net cash provided by financing activities

 

26,114

 

2,869

 

Net decrease in cash and cash equivalents

 

(3,513

)

(16,860

)

Cash and cash equivalents, beginning of period

 

24,143

 

17,697

 

Cash and cash equivalents, end of period

 

$

20,630

 

$

837

 

Cash paid for interest

 

$

34,183

 

$

33,693

 

Cash paid for income taxes

 

$

 

$

 

 

See accompanying notes to condensed consolidated financial statements.

 

7



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements

 

March 31, 2012

(Unaudited)

 

(1) General

 

Unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” mean Crosstex Energy, L.P. and its consolidated subsidiaries.

 

Crosstex Energy, L.P., a Delaware limited partnership formed on July 12, 2002, is engaged in the gathering, transmission, processing and marketing of natural gas, natural gas liquids, or NGLs, and providing terminal services for crude oil. The Partnership connects the wells of natural gas producers in the geographic areas of its gathering systems in order to gather for a fee or purchase the gas production, processes natural gas for the removal of NGLs, transports natural gas and NGLs and ultimately provides natural gas and NGLs to a variety of markets.  The Partnership operates processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee arrangements.  In addition, the Partnership purchases natural gas and NGLs from producers not connected to its gathering systems for resale and markets natural gas and NGLs on behalf of producers for a fee.  The Partnership recently added crude oil terminal facilities in south Louisiana to provide access for crude oil producers to the premium markets in this area.

 

Crosstex Energy GP, LLC is the general partner of the Partnership. Crosstex Energy GP, LLC is a direct, wholly-owned subsidiary of Crosstex Energy, Inc. (CEI).

 

(a) Basis of Presentation

 

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to the consolidated financial statements for the prior year to conform to the current presentation. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011.

 

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management of the Partnership to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

 

(b) Investment in Limited Liability Company

 

On June 22, 2011, the Partnership entered into a limited liability agreement with Howard Energy Partners (“HEP”) for an initial capital contribution of $35.0 million in exchange for an individual ownership interest in HEP of approximately 35.0 percent.  In addition to the Partnership’s contribution, an unrelated party also provided a capital contribution of $35.0 million for a 35.0 percent ownership interest in HEP with HEP management and a few private investors owning the remaining 30.0 percent interest.  HEP owns midstream assets and provides midstream and construction services to Eagle Ford Shale producers.  This investment in HEP is accounted for under the equity method of accounting and is reflected on the balance sheet as “Investment in limited liability company.”  On March 13, 2012, the Partnership made a $4.9 million capital contribution to HEP related to HEP’s announced definitive agreement to acquire substantially all of Meritage Midstream Services’ natural gas gathering assets in south Texas as described in Note (10) to the condensed consolidated financial statements.

 

(c) Potential Changes in use of Sabine Plant during 2012.

 

Currently, the Partnership’s Sabine plant has a contract with a third-party to fractionate the raw-make NGLs produced by the plant.  This contract, which was scheduled to expire on March 1, 2012, was extended through June 30, 2012 and may be extended on a month-to-month basis thereafter.  The Partnership will negotiate with this third-party to establish a long-term fractionation agreement. If this third-party ceases to fractionate the produced NGLs from the Sabine plant after June 30, 2012 and the partnership is unsuccessful in determining another alternative for our Sabine customers, the partnership will cease operation of the Sabine plant.  Although the partnership does not have specific plans at this time to relocate the Sabine plant if it is idled, the partnership may utilize it elsewhere in its operations.  The net book value of the Sabine plant was

 

8



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

$47.4 million (including $13.7 million of intangible assets attributable to customer relationships) as of March 31, 2012.  If the plant is idled on a long-term basis, an impairment may be recorded to expense the non-recoverable costs associated with the plant’s current location, which are estimated to be less than $28.0 million based on the net book value as of March 31, 2012.

 

(2) Long-Term Debt

 

As of March 31, 2012 and December 31, 2011, long-term debt consisted of the following (in thousands):

 

 

 

March 31,

 

December 31,

 

 

 

2012

 

2011

 

Bank credit facility (due 2016), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at March 31, 2012 and December 31, 2011 was 3.16% and 2.9%, respectively

 

$

139,000

 

$

85,000

 

Senior unsecured notes (due 2018), net of discount of $11.1 million and $11.6 million, respectively, which bear interest at the rate of 8.875%

 

713,883

 

713,409

 

Debt classified as long-term

 

$

852,883

 

$

798,409

 

 

Credit Facility. As of March 31, 2012, there was $59.8 million in outstanding letters of credit and $139.0 million borrowed under the Partnership’s bank credit facility, leaving approximately $436.2 million available for future borrowing based on the borrowing capacity of $635.0 million.  On January 24, 2012, the Partnership amended its credit facility.  This amendment increased its borrowing capacity from $485.0 million to $635.0 million and amended certain terms under the facility to provide additional financial flexibility during the remaining four-year term of the facility.  The credit facility is guaranteed by substantially all of the Partnership’s subsidiaries and is secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors, including all material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of the Partnership’s equity interests in substantially all of its subsidiaries and its interest in HEP.

 

The Partnership may prepay all loans under the amended credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.

 

All material terms of the credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

 

Non Guarantors.  The senior unsecured notes are jointly and severally guaranteed by each of the Partnership’s current material subsidiaries (the “Guarantors”), with the exception of its regulated Louisiana subsidiaries (which may only guarantee up to $500.0 million of the Partnership’s debt), CDC (the Partnership’s joint venture in Denton County, Texas which is not 100% owned by the Partnership) and Crosstex Energy Finance Corporation (a wholly owned Delaware corporation that was organized for the sole purpose of being a co-issuer of certain of the Partnership’s indebtedness, including the senior unsecured notes). Guarantors may not sell or otherwise dispose of all or substantially all of their properties or assets, or consolidate with or merge into another company if such a sale would cause a default under the terms of the senior unsecured notes. Since certain wholly owned subsidiaries do not guarantee the senior unsecured notes, the condensed consolidating financial statements of the guarantors and non-guarantors for the three months ended March 31, 2012 and 2011 are disclosed below in accordance with Rule 3-10 of Regulation S-X. Comprehensive income (loss) is not included in the condensed consolidating statements of operations of the guarantors and non-guarantors for the three months ended March 31, 2012 and 2011 as these amounts are not considered material.

 

9



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

Condensed Consolidating Balance Sheets

March 31, 2012

 

 

 

Guarantors

 

Non Guarantors

 

Elimination

 

Consolidated

 

 

 

(In thousands)

 

ASSETS

 

 

 

 

 

 

 

 

 

Total current assets

 

$

151,699

 

$

17,518

 

$

 

$

169,217

 

Property, plant and equipment, net

 

1,039,254

 

212,050

 

 

1,251,304

 

Total other assets

 

502,929

 

 

 

502,929

 

Total assets

 

$

1,693,882

 

$

229,568

 

$

 

$

1,923,450

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES & PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

Total current liabilities

 

$

152,973

 

$

4,281

 

$

 

$

157,254

 

Long-term debt

 

852,883

 

 

 

852,883

 

Other long-term liabilities

 

30,333

 

 

 

30,333

 

Partners’ capital

 

657,693

 

225,287

 

 

882,980

 

Total liabilities & partners’ capital

 

$

1,693,882

 

$

229,568

 

$

 

$

1,923,450

 

 

December 31, 2011

 

 

 

Guarantors

 

Non Guarantors

 

Elimination

 

Consolidated

 

 

 

(In thousands)

 

ASSETS

 

 

 

 

 

 

 

 

 

Total current assets

 

$

189,410

 

$

13,346

 

$

 

$

202,756

 

Property, plant and equipment, net

 

1,026,537

 

215,364

 

 

1,241,901

 

Total other assets

 

510,671

 

3

 

 

510,674

 

Total assets

 

$

1,726,618

 

$

228,713

 

$

 

$

1,955,331

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES & PARTNERS’ CAPITAL

 

 

 

 

 

 

 

 

 

Total current liabilities

 

$

220,811

 

$

4,541

 

$

 

$

225,352

 

Long-term debt

 

798,409

 

 

 

798,409

 

Other long-term liabilities

 

31,111

 

 

 

31,111

 

Partners’ capital

 

676,287

 

224,172

 

 

900,459

 

Total liabilities & partners’ capital

 

$

1,726,618

 

$

228,713

 

$

 

$

1,955,331

 

 

Condensed Consolidating Statements of Operations

For the Three Months Ended March 31, 2012

 

 

 

Guarantors

 

Non Guarantors

 

Elimination

 

Consolidated

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

357,153

 

$

22,277

 

$

(7,721

)

$

371,709

 

Total operating costs and expenses

 

(347,587

)

(9,108

)

7,721

 

(348,974

)

Operating income

 

9,566

 

13,169

 

 

22,735

 

Interest expense, net

 

(19,373

)

(9

)

 

(19,382

)

Other income

 

12

 

 

 

12

 

Income (loss) before non-controlling interest and income taxes

 

(9,795

)

13,160

 

 

3,365

 

Income tax provision

 

(420

)

(4

)

 

(424

)

Net loss attributable to non-controlling interest

 

 

(38

)

 

(38

)

Net income (loss) attributable to Crosstex Energy, L.P.

 

$

(10,215

)

$

13,194

 

$

 

$

2,979

 

 

For the Three Months Ended March 31, 2011

 

 

 

Guarantors

 

Non Guarantors

 

Elimination

 

Consolidated

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

474,940

 

$

21,903

 

$

(7,073

)

$

489,770

 

Total operating costs and expenses

 

(468,150

)

(8,710

)

7,073

 

(469,787

)

Operating income

 

6,790

 

13,193

 

 

19,983

 

Interest expense, net

 

(19,769

)

 

 

(19,769

)

Other income

 

113

 

 

 

113

 

Income (loss) before non-controlling interest and income taxes

 

(12,866

)

13,193

 

 

327

 

Income tax provision

 

(249

)

(4

)

 

(253

)

Net loss attributable to non-controlling interest

 

 

(54

)

 

(54

)

Net income (loss) attributable to Crosstex Energy, L.P.

 

$

(13,115

)

$

13,243

 

$

 

$

128

 

 

10



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

Condensed Consolidating Statements of Cash Flow

For the Three Months Ended March 31, 2012

 

 

 

Guarantors

 

Non Guarantors

 

Elimination

 

Consolidated

 

 

 

(In thousands)

 

Net cash flows provided by (used in) operating activities

 

$

(1,073

)

$

12,454

 

$

 

$

11,381

 

Net cash flows used in investing activities

 

$

(40,647

)

$

(361

)

$

 

$

(41,008

)

Net cash flows provided by (used in) financing activities

 

$

26,114

 

$

(12,040

)

$

12,040

 

$

26,114

 

 

For the Three Months Ended March 31, 2011

 

 

 

Guarantors

 

Non Guarantors

 

Elimination

 

Consolidated

 

 

 

(In thousands)

 

Net cash flows provided by (used in) operating activities

 

$

(12,615

)

$

14,435

 

$

 

$

1,820

 

Net cash flows provided by investing activities

 

$

(20,135

)

$

(1,414

)

$

 

$

(21,549

)

Net cash flows provided by (used in) financing activities

 

$

2,869

 

$

(12,511

)

$

12,511

 

$

2,869

 

 

(3) Other Long-term Liabilities

 

Prior to January 1, 2011, the Partnership entered into 9 and 10-year capital leases for certain equipment. Assets under capital leases as of March 31, 2012 are summarized as follows (in thousands):

 

Compressor equipment

 

$

37,199

 

Less: Accumulated amortization

 

(11,224

)

Net assets under capital leases

 

$

25,975

 

 

The following are the minimum lease payments to be made in each of the following years indicated for the capital leases in effect as of March 31, 2012 (in thousands):

 

2012

 

$

3,436

 

2013 through 2016 ($4,582 annually)

 

18,329

 

Thereafter

 

12,099

 

Less: Interest

 

(6,260

)

Net minimum lease payments under capital lease

 

27,604

 

Less: Current portion of net minimum lease payments

 

(4,448

)

Long-term portion of net minimum lease payments

 

$

23,156

 

 

11



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

(4)      Partners’ Capital

 

(a) Cash Distributions

 

Unless restricted by the terms of the Partnership’s credit facility and/or senior unsecured note indenture, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter.

 

The Partnership’s fourth quarter 2011 distribution on its common and preferred units of $0.32 per unit was paid on February 14, 2012.  The Partnership declared a first quarter 2012 distribution on its common and preferred units of $0.33 per unit to be paid on May 15, 2012.

 

(b) Earnings per Unit and Dilution Computations

 

The Partnership had common units and preferred units outstanding during the three months ended March 31, 2012 and March 31, 2011.

 

The preferred units are entitled to a quarterly distribution equal to the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. Income is allocated to the preferred units in an amount equal to the quarterly distribution with respect to the period earned.

 

As required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.  The following table reflects the computation of basic earnings per limited partner units for the periods presented (in thousands except per unit amounts):

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

Limited partners’ interest in net income

 

$

(1,803

)

$

(3,615

)

Distributed earnings allocated to:

 

 

 

 

 

Common units (1)(2)

 

$

16,783

 

$

14,625

 

Unvested restricted units (1)(2)

 

339

 

299

 

Total distributed earnings

 

$

17,122

 

$

14,924

 

Undistributed loss allocated to:

 

 

 

 

 

Common units

 

$

(18,551

)

$

(18,231

)

Unvested restricted units

 

(374

)

(308

)

Total undistributed loss

 

$

(18,925

)

$

(18,539

)

Net loss allocated to:

 

 

 

 

 

Common units

 

$

(1,768

)

$

(3,606

)

Unvested restricted units

 

(35

)

(9

)

Total limited partners’ interest in net income

 

$

(1,803

)

$

(3,615

)

Basic and diluted net loss per unit:

 

 

 

 

 

Basic and diluted common unit

 

$

(0.03

)

$

(0.07

)

 


(1)          Three months ended March 31, 2012 represents a declared distribution of $0.33 per unit payable on May 15, 2012.

(2)          Three months ended March 31, 2011 represents a declared distribution of $0.29 per unit paid on May 13, 2011.

 

12



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three months ended March 31, 2012 and 2011 (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

Basic and diluted weighted average units outstanding:

 

 

 

 

 

Weighted average limited partner common units outstanding

 

50,857

 

50,472

 

 

All common unit equivalents were antidilutive in the three months ended March 31, 2012 and March 31, 2011 because the limited partners were allocated net losses in these periods.

 

The general partner is entitled to a 2.0% distribution with respect to all distributions made to common unitholders. If the distributions are in excess of $0.2125 per unit, distributions are made 98.0% to the common and preferred unitholders and 2.0% to the general partner, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved.

 

When quarterly distributions are made pro-rata to common and preferred unitholders, net income for the general partner consists of incentive distributions to the extent earned, a deduction for stock-based compensation attributable to CEI’s stock options and restricted shares and 2.0% of the original Partnership’s net income (loss) adjusted for the CEI stock-based compensation specifically allocated to the general partner. When quarterly distributions are made solely to the preferred unitholders, the net income for the general partner consists of the CEI stock-based compensation deduction and 2.0% of the Partnership’s net income (loss) after the allocation of income to the preferred unitholders with respect to their preferred distribution adjusted for the CEI stock-based compensation specifically allocated to the general partner.

 

Under the quarterly incentive distribution provisions, generally the Partnership’s general partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23.0% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit. The net income (loss) allocated to the general partner is as follows (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

Income allocation for incentive distributions

 

$

979

 

$

398

 

Stock-based compensation attributable to CEI’s restricted shares

 

(1,133

)

(941

)

2% general partner interest in net income

 

83

 

21

 

General partner share of net income

 

$

(71

)

$

(522

)

 

(5) Employee Incentive Plans

 

(a)         Long-Term Incentive Plans

 

The Partnership accounts for share-based compensation in accordance with FASB ASC 718, which requires that compensation related to all stock-based awards, including stock options, be recognized in the consolidated financial statements.

 

The Partnership and CEI each have similar unit or share-based payment plans for employees, which are described below.  Share-based compensation associated with the CEI share-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since CEI has no operating activities other than its interest in the Partnership. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in thousands):

 

 

 

Three Months Ended
March 31,

 

 

 

2012

 

2011

 

Cost of share-based compensation charged to general and administrative expense

 

$

2,174

 

$

1,726

 

Cost of share-based compensation charged to operating expense

 

324

 

464

 

Total amount charged to income

 

$

2,498

 

$

2,190

 

 

13



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

(b)  Restricted Units

 

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the three months ended March 31, 2012 is provided below:

 

 

 

Three Months Ended March 31, 2012

 

Crosstex Energy, L.P. Restricted Units:

 

Number of
Units

 

Weighted
Average
Grant-Date
Fair Value

 

Non-vested, beginning of period

 

949,844

 

$

10.45

 

Granted

 

330,200

 

16.89

 

Vested*

 

(216,447

)

6.13

 

Forfeited

 

(3,245

)

13.38

 

Non-vested, end of period

 

1,060,352

 

$

13.33

 

Aggregate intrinsic value, end of period (in thousands)

 

$

18,121

 

 

 

 


* Vested units include 60,401 units withheld for payroll taxes paid on behalf of employees.

 

The Partnership issued restricted units in 2012 to officers and other employees. These restricted units typically vest at the end of three years and are included in the restricted units outstanding and the current share-based compensation cost calculations at March 31, 2012.

 

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the three months ended March 31, 2012 and 2011 are provided below (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

Crosstex Energy, L.P. Restricted Units:

 

2012

 

2011

 

Aggregate intrinsic value of units vested

 

$

3,511

 

$

4,239

 

Fair value of units vested

 

$

1,327

 

$

3,173

 

 

As of March 31, 2012, there was $8.7 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.1 years.

 

(c)  Unit Options

 

A summary of the unit option activity for the three months ended March 31, 2012 is provided below:

 

 

 

Three Months Ended March 31, 2012

 

 

 

 

 

Weighted

 

 

 

Number of

 

Average

 

Crosstex Energy, L.P. Unit Options:

 

Units

 

Exercise Price

 

Outstanding, beginning of period

 

451,574

 

$

6.99

 

Exercised

 

(34,668

)

5.17

 

Forfeited

 

(3,871

)

18.38

 

Outstanding, end of period

 

413,035

 

$

7.05

 

Options exercisable at end of period

 

345,668

 

 

 

Weighted average contractual term (years) end of period:

 

 

 

 

 

Options outstanding

 

6.9

 

 

 

Options exercisable

 

6.7

 

 

 

Aggregate intrinsic value end of period (in thousands):

 

 

 

 

 

Options outstanding

 

$

4,572

 

 

 

Options exercisable

 

$

3,825

 

 

 

 

14



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

A summary of the unit options intrinsic value exercised (market value in excess of exercise price at date of exercise) and fair value of units exercised (value per Black-Scholes-Merton option pricing model at date of grant) during the three months ended March 31, 2012 and March 31, 2011 are provided below (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

Crosstex Energy, L.P. Unit Options:

 

2012

 

2011

 

Intrinsic value of unit options exercised

 

$

411

 

$

506

 

Fair value of unit options vested

 

$

277

 

$

325

 

 

As of March 31, 2012, there was $0.2 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized during 2012.

 

(d)      Crosstex Energy, Inc.’s Restricted Stock

 

CEI’s restricted shares are valued at their fair value at the date of grant which is equal to the market value of the common stock on such date. A summary of the restricted share activities for the three months ended March 31, 2012 is provided below:

 

 

 

Three Months Ended
March 31, 2012

 

Crosstex Energy, Inc. Restricted Shares:

 

Number of
Shares

 

Weighted
Average
Grant-Date
Fair Value

 

Non-vested, beginning of period

 

1,221,351

 

$

7.40

 

Granted

 

427,990

 

13.38

 

Vested*

 

(216,447

)

4.65

 

Forfeited

 

(4,551

)

8.73

 

Non-vested, end of period

 

1,428,343

 

$

9.61

 

Aggregate intrinsic value, end of period (in thousands)

 

$

20,197

 

 

 

 


* Vested shares include 58,247 shares withheld for payroll taxes paid on behalf of employees.

 

CEI issued restricted shares in 2012 to officers and other employees. These restricted shares typically vest at the end of three years and are included in restricted shares outstanding and the current share-based compensation cost calculations at March 31, 2012.

 

A summary of the restricted shares’ aggregate intrinsic value (market value at vesting date) and fair value of shares vested (market value at date of grant) during the three months ended March 31, 2012 and March 31, 2011 are provided below (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

Crosstex Energy, Inc. Restricted Shares:

 

2012

 

2011

 

Aggregate intrinsic value of shares vested

 

$

2,736

 

$

2,578

 

Fair value of shares vested

 

$

1,006

 

$

2,890

 

 

As of March 31, 2012, there was $8.6 million of unrecognized compensation costs related to non-vested CEI restricted shares. The cost is expected to be recognized over a weighted average period of 2.2 years.

 

15



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

(e)       Crosstex Energy, Inc.’s Stock Options

 

CEI stock options have not been granted to officers or employees of the Partnership since 2005. There are 37,500 CEI stock options vested and exercisable at March 31, 2012.

 

(6) Derivatives

 

Commodity Swaps

 

The Partnership manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risks related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs.

 

The Partnership commonly enters into various derivative financial transactions which it does not designate as accounting hedges. These transactions include “swing swaps,” “third party on-system financial swaps,” “storage swaps,” “basis swaps,” “processing margin swaps,” “liquids swaps” and “put options.”  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. Third party on-system financial swaps are hedges that the Partnership enters into on behalf of its customers who are connected to its systems, wherein the Partnership fixes a supply or market price for a period of time for its customers, and simultaneously enters into the derivative transaction. Storage swap transactions protect against changes in the value of products that the Partnership has stored to serve various operational requirements (gas) or has in inventory due to short term constraints in moving the product to market (liquids). Basis swaps are used to hedge basis location price risk due to buying gas into one of the Partnership’s systems on one index and selling gas off that same system on a different index. Processing margin financial swaps are used to hedge fractionation spread risk at the Partnership’s processing plants relating to the option to process versus bypassing the Partnership’s equity gas.  Liquids financial swaps are used to hedge price risk on percent of liquids (POL) contracts. Put options are purchased to hedge against declines in pricing and as such represent options, not obligations, to sell the related underlying volumes at a fixed price.

 

The components of loss on derivatives in the condensed consolidated statements of operations relating to commodity swaps are provided below (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

Change in fair value of derivatives that do not qualify for hedge accounting

 

$

1,181

 

$

1,555

 

Realized losses on derivatives

 

1,026

 

1,761

 

Ineffective portion of derivatives qualifying for hedge accounting

 

(38

)

19

 

Net losses related to commodity swaps

 

$

2,169

 

$

3,335

 

Put option premium mark to market

 

 

86

 

Losses on derivatives

 

$

2,169

 

$

3,421

 

 

The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in thousands):

 

 

 

March 31,

 

December 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Fair value of derivative assets — current, designated

 

$

48

 

$

151

 

Fair value of derivative assets — current, non-designated

 

1,226

 

2,716

 

Fair value of derivative assets — long term, non-designated

 

131

 

 

Fair value of derivative liabilities — current, designated

 

(246

)

(702

)

Fair value of derivative liabilities — current, non-designated

 

(4,597

)

(4,885

)

Fair value of derivative liabilities — long term, non-designated

 

(110

)

 

Net fair value of derivatives

 

$

(3,548

)

$

(2,720

)

 

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets as of March 31, 2012 (all gas volumes are expressed in MMBtu’s and liquids volumes are expressed in

 

16



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

gallons). The remaining term of the contracts extend no later than December 2013 for derivatives. Changes in the fair value of the Partnership’s mark to market derivatives are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings. The ineffective portion is recorded in earnings immediately.

 

 

 

March 31, 2012

 

Transaction Type

 

Volume

 

Fair Value

 

 

 

(In thousands)

 

Cash Flow Hedges:*

 

 

 

 

 

Liquids swaps (short contracts)

 

(4,584

)

$

(198

)

Total swaps designated as cash flow hedges

 

 

 

$

(198

)

 

 

 

 

 

 

Mark to Market Derivatives:*

 

 

 

 

 

Swing swaps (long contracts)

 

195

 

$

 

Physical offsets to swing swap transactions (short contracts)

 

(195

)

 

Swing swaps (short contracts)

 

(450

)

(10

)

Physical offsets to swing swap transactions (long contracts)

 

450

 

 

 

 

 

 

 

 

Basis swaps (long contracts)

 

2,830

 

(10

)

Physical offsets to basis swap transactions (short contracts)

 

(2,830

)

4,509

 

Basis swaps (short contracts)

 

(2,830

)

17

 

Physical offsets to basis swap transactions (long contracts)

 

2,830

 

(6,267

)

 

 

 

 

 

 

Processing margin hedges — liquids (short contracts)

 

(13,569

)

357

 

Processing margin hedges — gas (long contracts)

 

1,600

 

(2,331

)

Processing margin hedges — gas (short contracts)

 

(187

)

287

 

 

 

 

 

 

 

Liquids swaps — (short contracts)

 

(4,393

)

(57

)

 

 

 

 

 

 

Storage swap transactions — gas (short contracts)

 

(290

)

155

 

 

 

 

 

 

 

Total mark to market derivatives

 

 

 

$

(3,350

)

 


*                 All are gas contracts, volume in MMBtu’s, except for liquids swaps (designated or non-designated) and processing margin hedges - liquids (volume in gallons).

 

On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss as of March 31, 2012 of $5.9 million would be reduced to $4.7 million due to the netting feature.

 

17



Table of Contents

 

CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

Impact of Cash Flow Hedges

 

The impact of realized gains or losses from derivatives designated as cash flow hedge contracts in the condensed consolidated statements of operations is summarized below (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

Decrease in Midstream Revenue

 

2012

 

2011

 

Liquids realized loss included in Midstream revenue

 

$

(12

)

$

(660

)

 

Natural Gas

 

As of March 31, 2012, the Partnership has no balances in accumulated other comprehensive income related to natural gas.

 

Liquids

 

As of March 31, 2012, an unrealized derivative fair value net loss of $0.2 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive loss,  all of which is expected to be reclassified into earnings through March 2013. The actual reclassification to earnings will be based on mark to market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected in the above table.

 

Derivatives Other Than Cash Flow Hedges

 

Assets and liabilities related to third party derivative contracts, swing swaps, basis swaps, storage swaps, processing margin swaps and liquids swaps are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as (gain) loss on derivatives in the condensed consolidated statement of operations. The Partnership estimates the fair value of all of its energy trading contracts using actively quoted prices. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):

 

 

 

Maturity Periods

 

 

 

Less than one year

 

One to two years

 

More than two years

 

Total fair value

 

March 31, 2012

 

$

(3,371

)

$

21

 

$

 

$

(3,350

)

 

(7)      Fair Value Measurements

 

FASB ASC 820 sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under FASB ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

 

FASB ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

 

The Partnership’s derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.

 

Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in thousands):

 

 

 

March 31, 2012

 

December 31, 2011

 

 

 

Level 2

 

Level 2

 

Commodity Swaps*

 

$

(3,548

)

$

(2,720

)

Total

 

$

(3,548

)

$

(2,720

)

 


*            Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income at each measurement date.  The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.

 

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CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

Fair Value of Financial Instruments

 

The estimated fair value of the Partnership’s financial instruments has been determined by the Partnership using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in thousands):

 

 

 

March 31, 2012

 

December 31, 2011

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

 

 

Value

 

Value

 

Value

 

Value

 

Long-term debt

 

$

852,883

 

$

910,219

 

$

798,409

 

$

882,500

 

Obligations under capital lease

 

$

27,604

 

$

29,776

 

$

28,367

 

$

27,637

 

 

The carrying amounts of the Partnership’s cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

 

The Partnership had $139.0 million in borrowings under its revolving credit facility included in long-term debt as of March 31, 2012 and $85.0 million at December 31, 2011. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of March 31, 2012 and December 31, 2011, the Partnership also had borrowings totaling $713.9 million and $713.4 million, net of discount, respectively, under senior unsecured notes with a fixed rate of 8.875%.  The fair value of the senior unsecured notes as of March 31, 2012 and December 31, 2011 was based on Level I inputs from third-party market quotations.  The fair value of obligations under capital leases was calculated using Level II inputs from third-party banks.

 

(8) Commitments and Contingencies

 

(a) Employment and Severance Agreements

 

Certain members of management of the Partnership are parties to employment and/or severance agreements with the general partner. The employment and severance agreements provide those managers with severance payments in certain circumstances and, in the case of employment agreements, prohibit each such person from competing with the general partner or its affiliates for a certain period of time following the termination of such person’s employment.

 

(b) Environmental Issues

 

The Partnership acquired LIG Pipeline Company and its subsidiaries on April 1, 2004. Contamination from historical operations was identified during due diligence at a number of sites owned by the acquired companies. The seller, AEP, has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third party company pursuant to which the remediation costs associated with these sites have been assumed by this third party company that specializes in remediation work. The Partnership does not expect to incur any material liability with these sites; however, there can be no assurance that the third parties who have assumed responsibility for remediation of site conditions will fulfill their obligations.

 

(c) Other

 

The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.

 

On June 7, 2010, Formosa Plastics Corporation, Texas, Formosa Plastics Corporation, America, Formosa Utility Venture, Ltd., and Nan Ya Plastics Corporation, America filed a lawsuit against Crosstex Energy, Inc., Crosstex Energy, L.P., Crosstex Energy GP, L.P., Crosstex Energy GP, LLC, Crosstex Energy Services, L.P., and Crosstex Gulf Coast Marketing, Ltd. in the 24th Judicial District Court of Calhoun County, Texas, asserting claims for negligence, res ipsa loquitor, products liability and strict liability relating to the

 

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CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

alleged receipt by the plaintiffs of natural gas liquids into their facilities from facilities operated by the Partnership.  The amended petition alleges that the plaintiffs have incurred at least $35.0 million in damages, including damage to equipment and lost profits.  The Partnership has submitted the claim to its insurance carriers and intends to vigorously defend the lawsuit.  The Partnership believes that any recovery would be within applicable policy limits. Although it is not possible to predict the ultimate outcome of this matter, the Partnership does not expect that an award in this matter will have a material adverse impact on its consolidated results of operations or financial condition.

 

At times, the Partnership’s gas-utility subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain provided under state law. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s gas utility subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

 

The Partnership (or its subsidiaries) is defending a number of lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas.  In January 2012, a plaintiff in one of these lawsuits was awarded a judgment of $2.0 million.  The Partnership intends to appeal the matter and will post a bond to secure the judgment pending its resolution.  The Partnership has accrued $2.0 million related to this matter as of March 31, 2012 and reflected the related expense in operating expenses in the fourth quarter of 2011.  Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

 

(9) Segment Information

 

Identification of operating segments is based principally upon regions served.  The Partnership’s reportable segments consist of the natural gas gathering, processing and transmission operations located in north Texas and in the Permian Basin in west Texas (NTX), the pipelines and processing plants located in Louisiana (LIG) and the south Louisiana processing and NGL assets (PNGL). Operating activity for assets sold in the comparative periods that was not considered discontinued operations as well as intersegment eliminations is shown in the corporate segment.  The Partnership’s sales are derived from external domestic customers.

 

The Partnership evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of property and equipment, including software, for general corporate support, working capital, debt financing costs, and its investment in HEP.

 

Summarized financial information concerning the Partnership’s reportable segments is shown in the following table.

 

 

 

LIG

 

NTX

 

PNGL

 

Corporate

 

Totals

 

 

 

(In thousands)

 

Three Months Ended March 31, 2012:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

146,697

 

$

64,681

 

$

160,331

 

$

 

$

371,709

 

Sales to affiliates

 

$

72,810

 

$

31,484

 

$

45,545

 

$

(149,839

)

$

 

Purchased gas and NGLs

 

$

(189,220

)

$

(50,021

)

$

(182,554

)

$

149,839

 

$

(271,956

)

Operating expenses

 

$

(7,936

)

$

(13,151

)

$

(6,719

)

$

 

$

(27,806

)

Segment profit

 

$

22,351

 

$

32,993

 

$

16,603

 

$

 

$

71,947

 

Gain (loss) on derivatives

 

$

102

 

$

(2,263

)

$

(8

)

$

 

$

(2,169

)

Depreciation, amortization and impairments

 

$

(3,153

)

$

(20,433

)

$

(7,959

)

$

(633

)

$

(32,178

)

Capital expenditures

 

$

8

 

$

13,156

 

$

15,662

 

$

454

 

$

29,280

 

Identifiable assets

 

$

286,911

 

$

1,092,530

 

$

463,249

 

$

80,760

 

$

1,923,450

 

Three Months Ended March 31, 2011:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

204,918

 

$

80,966

 

$

203,886

 

$

 

$

489,770

 

Sales to affiliates

 

22,322

 

21,585

 

485

 

(44,392

)

 

Purchased gas and NGLs

 

(195,503

)

(63,159

)

(185,663

)

44,392

 

(399,933

)

Operating expenses

 

(8,067

)

(11,352

)

(5,625

)

 

(25,044

)

Segment profit

 

$

23,670

 

$

28,040

 

$

13,083

 

$

 

$

64,793

 

Loss on derivatives

 

$

(2,685

)

$

(716

)

$

(20

)

$

 

$

(3,421

)

Depreciation, amortization and impairments

 

$

(3,142

)

$

(17,720

)

$

(7,713

)

$

(1,078

)

$

(29,653

)

Capital expenditures

 

$

1,550

 

$

18,203

 

$

4,083

 

$

487

 

$

24,323

 

Identifiable assets

 

$

323,881

 

$

1,110,852

 

$

489,147

 

$

35,445

 

$

1,959,325

 

 

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CROSSTEX ENERGY, L.P.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

The following table reconciles the segment profits reported above to the operating income as reported in the condensed consolidated statements of operations (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011

 

Segment profits

 

$

71,947

 

$

64,793

 

General and administrative expenses

 

(14,963

)

(11,755

)

Loss on derivatives

 

(2,169

)

(3,421

)

Gain on sale of property

 

98

 

19

 

Depreciation, amortization and impairments

 

(32,178

)

(29,653

)

Operating income

 

$

22,735

 

$

19,983

 

 

(10) Subsequent Event

 

Investment in HEP.  On April 4, 2012, the Partnership made a $47.4 million payment to HEP related to HEP’s acquisition of substantially all of Meritage Midstream Services’ natural gas gathering assets in south Texas which was funded by the Partnership’s credit facility.  After this capital contribution, the Partnership has contributed an aggregate of $87.3 million and has an individual ownership interest in HEP of approximately 30.6 percent.

 

Riverside Fractionation Facility Expansion. On May 7, 2012, the Partnership announced its plans to increase its capacity to transload crude oil from rail cars to both barges and pipeline at its Riverside fractionation facility in southern Louisiana from approximately 4,500 barrels of crude oil per day to approximately 15,000  barrels of crude per day.  The Phase I modification of the Riverside facility, which allowed crude as well as NGLs to be transloaded from rail to barge, was operational in January 2012.  The Phase II development at the Riverside facility will include new storage tank facilities, upgraded pipeline connections and improved barge delivery capabilities on the Mississippi River.  Construction of the Phase II expansion project at the Riverside facility will begin in late June 2012 and is expected be operational in the first quarter of 2013.  The Riverside facility expansion project is expected to cost approximately $16 million.  The Partnership has entered into a long-term agreement, which supports the expansion.

 

Clearfield Acquisition.  On May 8, 2012, the Partnership announced its agreement to acquire privately held Clearfield Energy, Inc. (“Clearfield”) for approximately $210 million in cash at closing subject to certain adjustments (the “Clearfield Acquisition”). Clearfield is a well-established crude oil, condensate and water services company with operations in Ohio, Kentucky and West Virginia.  Clearfield’s business includes crude oil pipelines, a barge loading terminal on the Ohio River, a rail loading terminal on the Ohio Central Railroad network, a trucking fleet, and brine water disposal wells.

 

The Partnership plans to fund the Clearfield Acquisition with a combination of debt and equity.  The closing of the Clearfield Acquisition, which is expected in July 2012, is subject to the satisfaction of customary closing conditions, including applicable regulatory approvals, if any.

 

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

 

You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report.

 

Overview

 

We are a Delaware limited partnership formed on July 12, 2002.  Our primary focus is on the gathering, processing, transmission and marketing of natural gas and natural gas liquids (NGLs), which we manage as regional reporting segments of midstream activity.   We recently added crude oil terminal facilities in south Louisiana to provide access for crude oil producers to the premium markets in this area.   Our geographic focus is in the north Texas Barnett shale (NTX) and in Louisiana which has two reportable business segments (the pipelines and processing plants located in Louisiana, or LIG, and the south Louisiana processing and NGL assets, or PNGL).  During 2011, we gained a presence in the Permian Basin in west Texas through a joint project with Apache Corporation, which is included in our NTX segment and also gained access in the Eagle Ford shale in south Texas by our equity investment in Howard Energy Partners (“HEP”), which is included with our corporate assets for segment reporting.

 

We manage our operations by focusing on gross operating margin because our business is generally to purchase and resell natural gas and NGLs for a margin, or to gather, process, transport or market natural gas and NGLs for a fee.  We earn a volume based fee for providing crude oil services.  We define gross operating margin as operating revenue minus cost of purchased gas and NGLs.  Gross operating margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below.

 

Our gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facilities, the volumes of NGLs handled at our fractionation facilities and the volumes of crude oil handled at our crude terminals. We generate revenues from five primary sources:

 

·                  purchasing and reselling or transporting natural gas on the pipeline systems we own;

 

·                  processing natural gas at our processing plants;

 

·                  fractionating and marketing the recovered NGLs;

 

·                  providing compression services; and

 

·                  providing crude oil terminal services.

 

We generally gather or transport gas owned by others through our facilities for a fee, or we buy natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transport and resell the natural gas at the market index. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction.  Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas.  We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time the supplies that we have under contract may decline due to reduced drilling or other causes and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, on occasion we have entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and we capture the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as our margin. Changes in the basis spread can increase or decrease our margins.

 

One contract (the “Delivery Contract”) has a term to 2019 that obligates us to supply approximately 150,000 MMBtu/d of gas.  At the time that we entered into the Delivery Contract in 2008, we had dedicated supply sources in the Barnett Shale that exceeded the delivery obligations under the Delivery Contract.  Our agreements with these suppliers generally provided that the purchase price for the gas was equal to a portion of our sales price for such gas less certain fees and costs.  Accordingly, we were initially able to generate a positive margin under the Delivery Contract.  However, since entering into the Delivery Contract, there has been both (1) a reduction in the gas available under our supply contracts and (2) the discovery of other shale reserves, most notably the Haynesville and the Marcellus Shales, which has increased the supplies available to east coast markets and reduced the basis spread between north Texas-area production and the market indices used in the Delivery Contract.  Due to these factors, we have had to purchase a portion

 

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of the gas necessary to fulfill our obligations under the Delivery Contract at market prices, resulting in negative margins under the Delivery Contract.

 

We have recorded a loss of approximately $3.8 million during the three months ended March 31, 2012 on the Delivery Contract.  We currently expect that we will record an additional loss of approximately $11.8 million on the Delivery Contract for the remainder of the year ending December 31, 2012.  This estimate is based on forward prices, basis spreads and other market assumptions as of March 31, 2012. These assumptions are subject to change if market conditions change during the remainder of 2012, and actual results under the Delivery Contract in 2012 could be substantially different from our current estimates, which may result in a greater loss than currently estimated.

 

We also realize gross operating margins from our processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fixed-fee based. Under margin contract arrangements our gross operating margins are higher during periods of high liquid prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Under fixed-fee based contracts our gross operating margins are driven by throughput volume. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

 

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services and utilities. These costs are normally fairly stable across broad volume ranges, and therefore do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas or liquids moved through the asset.

 

Our general and administrative expenses are dictated by the terms of our partnership agreement. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of business and allocable to us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

 

Recent Developments

 

Credit Facility. On January 24, 2012, we amended our credit facility.  This amendment increased our borrowing capacity from $485.0 million to $635.0 million and amended certain terms in the facility to provide additional financial flexibility during the remaining four-year term of the facility as described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation — Indebtedness” in our Annual Report on Form 10-K for the year ended December 31, 2011.

 

Investment in Limited Liability Company.  On March 15, 2012, HEP announced that it entered into a definitive agreement to acquire substantially all of Meritage Midstream Services’ natural gas gathering assets in south Texas.  This acquisition was funded primarily by capital contributions by the Partnership and other unrelated parties.  In June 2011, the Partnership had originally invested $35.0 million for an ownership interest in HEP of about 35.0 percent.  The capital contribution related to the Meritage acquisition was a total of $52.3 million, with $4.9 million paid in March 2012 and the remaining $47.4 million paid in April 2012 which was funded by the Partnership’s credit facility.

 

After closing of the acquisition and including initial investments, the Partnership has contributed a total of $87.3 million for an ownership interest in HEP of approximately 30.6 percent.  HEP operates and manages midstream services as well as pipeline and plant construction primarily in the Eagle Ford shale in south Texas.

 

Riverside Fractionation Facility Expansion.  On May 7, 2012, the Partnership announced its plans to increase its capacity to transload crude oil from rail cars to both barges and pipeline at its Riverside fractionation facility in southern Louisiana from approximately 4,500 barrels of crude oil per day to approximately 15,000  barrels of crude per day.  The Phase I modification of the Riverside facility, which allowed crude as well as NGLs to be transloaded from rail to barge, was operational in January 2012.  The Phase II development at the Riverside facility will include new storage tank facilities, upgraded pipeline connections and improved barge delivery capabilities on the Mississippi River.  Construction of the Phase II expansion project at Riverside will begin in late June 2012 and is expected be operational in the first quarter of 2013.  The expansion project is expected to cost approximately $16 million.  The Partnership has entered into a long-term agreement, which supports the expansion.

 

Clearfield Acquisition.  On May 8, 2012, the Partnership announced its agreement to acquire privately held Clearfield Energy, Inc. (“Clearfield”) for approximately $210 million in cash at closing, subject to certain adjustments (the “Clearfield Acquisition”). Clearfield is a crude oil, condensate and water services company with operations in Ohio, Kentucky and West Virginia.  Clearfield currently moves approximately 30 percent of the oil production in Ohio and provides a solid entry into the Utica Shale play where major producers have acquired significant acreage positions.  The Partnership expects this acquisition to be immediately accretive to distributable cash flow.

 

The Clearfield Acquisition further diversifies the Partnership’s asset base in terms of geography and service offerings, representing an important strategic step for the Partnership into crude and condensate services. As Utica Shale production expands, the Partnership plans to leverage Clearfield’s first-mover position in crude and condensate services in the region, which will drive further growth.  The Partnership believes its core capabilities and strong financial performance will enable it to leverage Clearfield’s strategically positioned assets and operational platform to accelerate growth.  This platform will better enable the Partnership to compete for natural gas gathering and processing opportunities in the emerging Utica Shale play.

 

Clearfield’s assets include a 4,500-barrel-per-hour crude oil barge loading terminal on the Ohio River, a 28,000-barrel-per day crude oil rail loading terminal on the Ohio Central Railroad network which is expected to expand to a 56,000-barrel-per-day facility by end-of-year, and 200 miles of crude oil pipelines in Ohio and West Virginia.  The assets also include 100,000 barrels of above ground storage, six existing brine water disposal wells with two under development and an extensive fleet of trucks with a total capacity of 35,000 barrels per day.  In addition, Clearfield owns more than 2,500 miles of unused right of way.

 

The Partnership plans to fund the Clearfield Acquisition with a combination of debt and equity.  The closing of the Clearfield Acquisition, which is expected to occur in July 2012, is subject to the satisfaction of customary closing conditions, including applicable regulatory approvals, if any.

 

Non-GAAP Financial Measures

 

We include the following non-generally accepted accounting principles, or non-GAAP, financial measures: Adjusted earnings before interest, taxes, depreciation and amortization, or adjusted EBITDA, and gross operating margin.

 

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We define adjusted EBITDA as net income plus interest expense, provision for income taxes, depreciation and amortization expense, impairments, stock-based compensation, (gain) loss on noncash derivatives, and minority interest; less gain on sale of property. Adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

 

·                  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 pay interest costs, support our indebtedness and make cash distributions to our unitholders and our general partner;

 

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

 

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

 

Adjusted EBITDA is one of the critical inputs into the financial covenants within our credit facility. The rates we pay for borrowings under our credit facility are determined by the ratio of our debt to adjusted EBITDA.  The calculation of these ratios allows for further adjustments to adjusted EBITDA for recent acquisitions and dispositions.

 

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other entities may not calculate adjusted EBITDA in the same manner.

 

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.

 

The following table provides a reconciliation of adjusted EBITDA to net income (loss):

 

 

 

Three Months Ended March
31,

 

 

 

2012

 

2011

 

 

 

(In millions)

 

 

 

 

 

 

 

Net income attributable to Crosstex Energy, L.P.

 

$

3.0

 

$

0.1

 

Interest expense

 

19.4

 

19.8

 

Depreciation and amortization

 

32.2

 

29.7

 

Gain on sale of property

 

(0.1

)

 

Stock-based compensation

 

2.5

 

2.2

 

Other (a)

 

1.5

 

1.8

 

Adjusted EBITDA

 

$

58.5

 

$

53.6

 

 


(a) Includes financial derivatives marked-to-market; income taxes; and minority interest.

 

We define gross operating margin, generally, as revenues minus cost of purchased gas and NGLs. We present gross operating margin by segment in “Results of Operations.”  We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because our business is generally to purchase and resell natural gas for a margin or to gather, process, transport or market natural gas and NGLs for a fee. Operating expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operating expenses from total revenue in calculating gross operating margin because we separately evaluate commodity volume and price changes in these margin amounts. As an indicator of our operating performance, gross operating margin should not be considered an alternative to, or more meaningful

 

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than, net income as determined in accordance with GAAP. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

 

 

The following table provides a reconciliation of gross operating margin to operating income:

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2012

 

2011