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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, 2011

 

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: 000-50536

 

CROSSTEX ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

52-2235832

(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 o 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 26, 2011, the Registrant had 47,096,709 shares of common stock outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

Item

 

Description

 

Page

 

 

 

 

 

PART I—FINANCIAL INFORMATION

 

 

 

 

3

1.

 

Financial Statements

 

 

 

 

 

 

 

2.

 

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

 

21

 

 

 

 

 

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

 

34

 

2



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Condensed Consolidated Balance Sheets

 

 

 

March 31,

 

December 31,

 

 

 

2011

 

2010

 

 

 

(Unaudited)

 

 

 

 

 

(In thousands)

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

5,827

 

$

22,780

 

Accounts and notes receivable, net:

 

 

 

 

 

Trade, accrued revenue and other

 

206,447

 

209,998

 

Fair value of derivative assets

 

5,977

 

5,523

 

Natural gas and natural gas liquids, prepaid expenses and other

 

11,296

 

9,780

 

Total current assets

 

229,547

 

248,081

 

Property and equipment, net of accumulated depreciation of $348,500 and $329,741, respectively

 

1,221,669

 

1,216,166

 

Fair value of derivative assets

 

47

 

1,169

 

Intangible assets, net of accumulated amortization of $162,647 and $151,735, respectively

 

488,063

 

498,975

 

Other assets, net

 

25,267

 

26,712

 

Total assets

 

$

1,964,593

 

$

1,991,103

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable, drafts payable, accrued gas purchases and other

 

$

174,356

 

$

178,937

 

Fair value of derivative liabilities

 

10,692

 

7,980

 

Current portion of long-term debt

 

7,058

 

7,058

 

Other current liabilities

 

45,464

 

66,887

 

Total current liabilities

 

237,570

 

260,862

 

Long-term debt

 

727,986

 

711,512

 

Other long-term liabilities

 

26,152

 

26,879

 

Deferred tax liability

 

88,087

 

89,216

 

Fair value of derivative liabilities

 

349

 

1,156

 

Commitments and contingencies

 

 

 

Stockholders’ equity

 

884,449

 

901,478

 

Total liabilities and stockholders’ equity

 

$

1,964,593

 

$

1,991,103

 

 

See accompanying notes to condensed consolidated financial statements.

 

3



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Condensed Consolidated Statements of Operations

 

 

 

Three Months Ended March 31,

 

 

 

2011

 

2010

 

 

 

(Unaudited)

 

 

 

(In thousands, except per share 
amounts)

 

Revenues

 

$

450,315

 

$

468,658

 

Operating costs and expenses:

 

 

 

 

 

Purchased gas and NGLs

 

360,478

 

387,463

 

Operating expenses

 

25,044

 

26,465

 

General and administrative

 

12,481

 

13,481

 

Gain on sale of property

 

(19

)

(14,343

)

Loss on derivatives

 

3,421

 

3,696

 

Impairments

 

 

998

 

Depreciation and amortization

 

29,672

 

27,110

 

Total operating costs and expenses

 

431,077

 

444,870

 

Operating income

 

19,238

 

23,788

 

Other income (expense):

 

 

 

 

 

Interest expense, net of interest income

 

(19,767

)

(26,855

)

Loss on extinguishment of debt

 

 

(14,713

)

Other income

 

113

 

182

 

Total other income (expense)

 

(19,654

)

(41,386

)

Loss before non-controlling interest and income taxes

 

(416

)

(17,598

)

Income tax benefit

 

650

 

2,585

 

Net income (loss)

 

234

 

(15,013

)

Less: Net income (loss) attributable to the non-controlling interest

 

1,770

 

(9,611

)

Net loss attributable to Crosstex Energy, Inc.

 

$

(1,536

)

$

(5,402

)

Net loss per common share:

 

 

 

 

 

Basic common share

 

$

(0.03

)

$

(0.11

)

Diluted common share

 

$

(0.03

)

$

(0.11

)

Weighted average shares outstanding:

 

 

 

 

 

Basic

 

47,075

 

46,575

 

Diluted

 

47,075

 

46,575

 

 

See accompanying notes to condensed consolidated financial statements.

 

4



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Changes in Stockholders’ Equity

Three Months Ended March 31, 2011

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

Additional

 

Retained

 

Other

 

Non-

 

 

 

 

 

Common Stock

 

Paid in

 

Earning

 

Comprehensive

 

Controlling

 

 

 

 

 

Shares

 

Amount

 

Capital

 

(Deficit)

 

Income (loss)

 

Interest

 

Total

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Balance, December 31, 2010

 

46,894

 

$

468

 

$

242,390

 

$

(58,298

)

$

(145

)

$

717,063

 

$

901,478

 

Stock-based compensation

 

 

 

1,006

 

 

 

1,249

 

2,255

 

Common dividends

 

 

 

 

(3,838

)

 

 

(3,838

)

Net income (loss)

 

 

 

 

(1,536

)

 

1,770

 

234

 

Conversion of restricted stock for common, net of shares withheld for taxes

 

198

 

2

 

(787

)

 

 

 

(785

)

Hedging gains or losses reclassified to earnings

 

 

 

 

 

65

 

284

 

349

 

Adjustment in fair value of derivatives

 

 

 

 

 

(234

)

(1,024

)

(1,258

)

Non-controlling partner’s impact of conversion of restricted units and options exercise

 

 

 

 

 

 

(1,104

)

(1,104

)

Distribution to non-controlling interest

 

 

 

 

 

 

(12,882

)

(12,882

)

Balance, March 31, 2011

 

47,092

 

$

470

 

$

242,609

 

$

(63,672

)

$

(314

)

$

705,356

 

$

884,449

 

 

See accompanying notes to condensed consolidated financial statements.

 

5



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Comprehensive Income

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Net income (loss)

 

$

234

 

$

(15,013

)

Change in Non-controlling interest’s portion of accumulated other comprehensive income due to the issuance of units by Partnership, net of taxes of $68

 

 

115

 

Hedging gains reclassified to earnings, net of taxes of $38 and $140, respectively

 

65

 

238

 

Adjustment in fair value of derivatives, net of taxes $(138) and $41, respectively

 

(234

)

70

 

Comprehensive income (loss)

 

65

 

(14,590

)

Less: Comprehensive income (loss) attributable to the non-controlling interest

 

1,770

 

(9,611

)

Comprehensive loss attributable to Crosstex Energy, Inc.

 

$

(1,705

)

$

(4,979

)

 

See accompanying notes to condensed consolidated financial statements.

 

6



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Cash Flows

 

 

 

Three Months Ended March 31,

 

 

 

2011

 

2010

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

 

$

234

 

$

(15,013

)

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

 

 

 

 

 

Depreciation and amortization

 

29,672

 

27,110

 

Gain on sale of property

 

(19

)

(14,343

)

Impairments

 

 

998

 

Deferred tax benefit

 

(1,028

)

(3,285

)

Non-cash stock-based compensation

 

2,255

 

2,584

 

Derivatives mark to market interest rate settlement

 

 

(24,160

)

Non-cash portion of derivatives loss

 

1,574

 

2,288

 

Non-cash portion of loss on debt extinguishment

 

 

5,396

 

Payment of interest paid-in-kind debt

 

 

(11,558

)

Amortization of debt issue costs

 

1,552

 

2,128

 

Amortization of discount on notes

 

474

 

263

 

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable, accrued revenue and other

 

3,551

 

12,701

 

Natural gas and natural gas liquids, prepaid expenses and other

 

(1,512

)

2,214

 

Accounts payable, accrued gas purchases and other accrued liabilities

 

(35,011

)

(12,646

)

Fair value of derivatives

 

(10

)

 

Net cash provided by (used in) operating activities

 

1,732

 

(25,323

)

Cash flows from (used in) investing activities:

 

 

 

 

 

Additions to property and equipment

 

(21,596

)

(9,670

)

Insurance recoveries on property and equipment

 

 

874

 

Proceeds from sale of property

 

47

 

39,675

 

Net cash provided by (used in) investing activities

 

(21,549

)

30,879

 

Cash flows from (used in) financing activities:

 

 

 

 

 

Proceeds from borrowings

 

84,250

 

809,862

 

Payments on borrowings

 

(68,250

)

(908,160

)

Payments on capital lease obligations

 

(723

)

(556

)

Increase (decrease) in drafts payable

 

6,302

 

(1,622

)

Debt refinancing costs

 

(106

)

(28,063

)

Conversion of restricted stock, net of shares withheld for taxes

 

(785

)

(129

)

Distributions to non-controlling partners in the Partnership

 

(12,882

)

(184

)

Common dividend paid

 

(3,838

)

 

Conversion of restricted units, net of units withheld for taxes

 

(1,328

)

(1,772

)

Proceeds from exercise of Partnership unit options

 

224

 

140

 

Proceeds from issuance of Partnership units

 

 

120,786

 

Net cash provided (used in) financing activities

 

2,864

 

(9,698

)

Net decrease in cash and cash equivalents

 

(16,953

)

(4,142

)

Cash and cash equivalents, beginning of period

 

22,780

 

10,703

 

Cash and cash equivalents, end of period

 

$

5,827

 

$

6,561

 

Cash paid for interest

 

$

33,693

 

$

26,696

 

Cash paid for income taxes

 

$

 

$

1,195

 

 

See accompanying notes to condensed consolidated financial statements.

 

7



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

March 31, 2011

(Unaudited)

 

(1) General

 

Unless the context requires otherwise, references to “we,” “us,” “our,” “CEI” or the “Company” mean Crosstex Energy, Inc. and its consolidated subsidiaries.

 

Crosstex Energy, Inc., a Delaware corporation formed on April 28, 2000, is engaged, through its subsidiaries, in the gathering, transmission, processing and marketing of natural gas and natural gas liquids (NGLs). The Company 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. In addition, the Company 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 accompanying condensed consolidated financial statements include the assets, liabilities and results of operations of the Company, its majority owned subsidiaries and Crosstex Energy, L.P. (herein referred to as the Partnership or CELP), a publicly traded Delaware limited partnership.  The Partnership is included because CEI controls the general partner of the Partnership.

 

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 Company’s annual report on Form 10-K for the year ended December 31, 2010.

 

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management of the Company 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.

 

(2) Long-Term Debt

 

As of March 31, 2011 and December 31, 2010, long-term debt consisted of the following (in thousands):

 

 

 

March 31,

 

December 31,

 

 

 

2011 

 

2010

 

Bank credit facility (due 2016), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at March 31, 2011 and December 31, 2010 was 4.75% and 4.0%, respectively

 

$

16,000

 

$

 

Senior unsecured notes (due 2018), net of discount of $13.0 million and $13.5 million, respectively, which bear interest at the rate of 8.875%

 

711,986

 

711,512

 

Series B secured note assumed in the Eunice transaction (due 2011), which bears interest at the rate of 9.5%

 

7,058

 

7,058

 

 

 

735,044

 

718,570

 

Less current portion

 

(7,058

)

(7,058

)

Debt classified as long-term

 

$

727,986

 

$

711,512

 

 

8



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

Credit Facility. As of March 31, 2011, there was $73.2 million in outstanding letters of credit and $16.0 million borrowed under the bank credit facility leaving approximately $330.8 million available for future borrowing based on the borrowing capacity of $420.0 million. In May 2011 the Partnership amended its credit facility as discussed in Note (13).

 

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.

 

(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, 2011 are summarized as follows (in thousands):

 

Compressor equipment

 

$

37,199

 

Less: Accumulated amortization

 

(7,773

)

Net assets under capital lease

 

$

29,426

 

 

The following are the minimum lease payments to be made in each of the following years indicated for the capital lease in effect as of March 31, 2011 (in thousands):

 

2011

 

$

3,437

 

2012 through 2015 ($4,582 annually)

 

18,328

 

Thereafter

 

16,680

 

Less: Interest

 

(7,845

)

Net minimum lease payments under capital lease

 

30,600

 

Less: Current portion of net minimum lease payments

 

(4,448

)

Long-term portion of net minimum lease payments

 

$

26,152

 

 

(4)      Certain Provisions of the Partnership Agreement

 

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 2010 distribution on its common and preferred units of $0.26 per unit was paid on February 11, 2011.  The Partnership increased its first quarter 2011 distribution on its common and preferred units to $0.29 per unit to be paid on May 13, 2011.

 

(5) Earnings per Share and Dilution Computations

 

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the three months ended March 31, 2011 and 2010.  The computation of diluted earnings per share further assumes the dilutive effect of common share options and restricted shares.  All common share equivalents were antidilutive in the three months ended March 31, 2011 and March 31, 2010 because the Company had a net loss for the periods.

 

9



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

The following table reflects the computation of basic earnings per share for the periods presented (in thousands except per share amounts):

 

 

 

Three Months Ended March 31,

 

 

 

2011

 

2010

 

Net loss attributable to Crosstex Energy, Inc.

 

$

(1,536

)

$

(5,402

)

Distributed earnings allocated to:

 

 

 

 

 

Common shares

 

$

3,763

 

$

 

Unvested restricted shares

 

75

 

 

Total distributed earnings

 

$

3,838

 

$

 

Undistributed loss allocated to:

 

 

 

 

 

Common shares

 

$

(5,265

)

$

(5,250

)

Unvested restricted shares

 

(109

)

(152

)

Total undistributed loss

 

$

(5,374

)

$

(5,402

)

Net loss allocated to:

 

 

 

 

 

Common shares

 

$

(1,502

)

$

(5,250

)

Unvested restricted shares

 

(34

)

(152

)

Total net loss

 

$

(1,536

)

$

(5,402

)

Basic and diluted net loss per share:

 

 

 

 

 

Basic common share

 

$

(0.03

)

$

(0.11

)

Diluted common share

 

(0.03

)

(0.11

)

 

The following are the common share amounts used to compute the basic and diluted earnings per common share for the three months ended March 31, 2011 and 2010 (in thousands):

 

 

 

Three Months Ended March 31,

 

 

 

2011

 

2010

 

Basic and diluted weighted average shares outstanding:

 

 

 

 

 

Weighted average common shares outstanding

 

47,075

 

46,575

 

 

(6) Employee Incentive Plans

 

(a)         Long-Term Incentive Plans

 

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

 

The Company and the Partnership each have similar unit or share-based payment plans for employees, which are described below.  Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

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

 

$

1,790

 

$

2,162

 

Cost of share-based compensation charged to operating expense

 

465

 

422

 

Total amount charged to income

 

$

2,255

 

$

2,584

 

Interest of non-controlling partners in share-based compensation

 

$

910

 

$

1,032

 

Amount of related income tax benefit recognized in income

 

$

499

 

$

575

 

 

10



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

(b)Partnership 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, 2011 is provided below:

 

 

 

Three Months Ended March 31, 2011

 

Crosstex Energy, L.P. Restricted Units:

 

Number of
Units

 

Weighted 
Average 
Grant-Date
Fair Value

 

Non-vested, beginning of period

 

1,047,374

 

$

10.30

 

Granted

 

273,547

 

15.04

 

Vested*

 

(287,951

)

11.02

 

Forfeited

 

(1,393

)

6.00

 

Non-vested, end of period

 

1,031,577

 

$

11.36

 

Aggregate intrinsic value, end of period (in thousands)

 

$

17,454

 

 

 

 


* Vested units include 90,264 units withheld for payroll taxes paid on behalf of employees.

 

The Partnership issued restricted units in 2011 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, 2011.

 

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, 2011 and 2010 are provided below (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

Crosstex Energy, L.P. Restricted Units:

 

2011

 

2010

 

Aggregate intrinsic value of units vested

 

$

4,239

 

$

6,316

 

Fair value of units vested

 

$

3,173

 

$

2,518

 

 

As of March 31, 2011, there was $7.1 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.3 years.

 

(c) Partnership Unit Options

 

A summary of the unit option activity for the three months ended March 31, 2011 is provided below:

 

 

 

Three Months Ended March 31, 2011

 

 

 

 

 

Weighted

 

 

 

Number of

 

Average

 

Crosstex Energy, L.P. Unit Options:

 

Units

 

Exercise Price

 

Outstanding, beginning of period

 

611,311

 

$

6.77

 

Exercised

 

(48,610

)

4.63

 

Forfeited

 

(6,478

)

5.50

 

Expired

 

 

 

Outstanding, end of period

 

556,223

 

$

6.97

 

Options exercisable at end of period

 

309,769

 

$

8.11

 

Weighted average contractual term (years) end of period:

 

 

 

 

 

Options outstanding

 

7.9

 

 

 

Options exercisable

 

7.5

 

 

 

Aggregate intrinsic value end of period (in thousands):

 

 

 

 

 

Options outstanding

 

$

6,119

 

 

 

Options exercisable

 

$

3,312

 

 

 

 

11



Table of Contents

 

CROSSTEX ENERGY, INC.

 

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 vested (value per Black-Scholes-Merton option pricing model at date of grant) during the three months ended March 31, 2011 and 2010 are provided below (in thousands):

 

 

 

Three Months Ended March 31,

 

Crosstex Energy, L.P. Unit Options:

 

2011

 

2010

 

Intrinsic value of unit options exercised

 

$

506

 

$

159

 

Fair value of units vested

 

$

325

 

$

35

 

 

As of March 31, 2011, there was $0.5 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted average period of 1.6 years.

 

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

 

The Company’s restricted shares are included 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, 2011 is provided below:

 

 

 

Three Months Ended

 

 

 

March 31, 2011

 

Crosstex Energy, Inc. Restricted Shares:

 

Number of 
Shares

 

Weighted 
Average 
Grant-Date 
Fair Value

 

 

 

 

 

 

 

Non-vested, beginning of period

 

1,108,998

 

$

8.64

 

Granted

 

444,595

 

8.61

 

Vested*

 

(285,564

)

10.12

 

Forfeited

 

(1,393

)

4.85

 

Non-vested, end of period

 

1,266,636

 

$

8.30

 

Aggregate intrinsic value, end of period (in thousands)

 

$

12,594

 

 

 

 


* Vested shares include 87,279 shares withheld for payroll taxes paid on behalf of employees.

 

The Company issued restricted shares in 2011 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, 2011.

 

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, 2011 and 2010 are provided below (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

Crosstex Energy, Inc. Restricted Shares:

 

2011

 

2010

 

Aggregate intrinsic value of shares vested

 

$

2,578

 

$

315

 

Fair value of shares vested

 

$

2,890

 

$

1,026

 

 

As of March 31, 2011, there was $6.2 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 2.3 years.

 

12



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

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

 

CEI stock options have not been granted as a means of compensation since 2005. All units outstanding at December 31, 2009 were vested and exercisable with all associated costs recognized.  The following is a summary of the CEI stock options outstanding as of March 31, 2011:

 

 

 

Three Months Ended March 31, 2011

 

 

 

 

 

Weighted

 

 

 

Number of

 

Average

 

Crosstex Energy, Inc. Stock Options:

 

Shares

 

Exercise Price

 

Outstanding, beginning of period

 

37,500

 

$

6.50

 

Forfeited

 

 

 

Outstanding, end of period

 

37,500

 

$

6.50

 

Options exercisable at end of period

 

37,500

 

$

6.50

 

Weighted average contractual term (years) end of period

 

3.7

 

 

 

 

(7) 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,” 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 gas that the Partnership has stored to serve various operational requirements. 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.  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 (in thousands):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

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

 

$

1,555

 

$

2,348

 

Realized losses on derivatives

 

1,761

 

1,408

 

Ineffective portion of derivatives qualifying for hedge accounting

 

19

 

(60

)

Net losses related to commodity swaps

 

$

3,335

 

$

3,696

 

Put option premium mark to market

 

86

 

 

Losses on derivatives

 

$

3,421

 

$

3,696

 

 

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

 

13



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

 

 

March 31,

 

December 31,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Fair value of derivative assets — current, designated

 

$

3

 

$

1

 

Fair value of derivative assets — current, non-designated

 

5,974

 

5,522

 

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

 

47

 

1,169

 

Fair value of derivative liabilities — current, designated

 

(1,910

)

(1,066

)

Fair value of derivative liabilities — current, non-designated

 

(8,782

)

(6,914

)

Fair value of derivative liabilities — long term, designated

 

(187

)

 

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

 

(162

)

(1,156

)

Net fair value of derivatives

 

$

(5,017

)

$

(2,444

)

 

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at March 31, 2011 (all gas volumes are expressed in MMBtu’s and liquids volumes are expressed in gallons). The remaining term of the contracts extend no later than December 2012 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, 2011

 

Transaction Type

 

Volume

 

Fair Value

 

 

 

(In thousands)

 

Cash Flow Hedges:*

 

 

 

 

 

Liquids swaps (short contracts)

 

(12,249

)

$

(2,093

)

Total swaps designated as cash flow hedges

 

 

 

$

(2,093

)

 

 

 

 

 

 

Mark to Market Derivatives:*

 

 

 

 

 

Swing swaps (short contracts)

 

(4,065

)

$

(4

)

Physical offsets to swing swap transactions (long contracts)

 

4,065

 

(48

)

 

 

 

 

 

 

Basis swaps (long contracts)

 

21,243

 

4,430

 

Physical offsets to basis swap transactions (short contracts)

 

(803

)

3,174

 

Basis swaps (short contracts)

 

(19,103

)

(4,194

)

Physical offsets to basis swap transactions (long contracts)

 

803

 

(3,297

)

 

 

 

 

 

 

Third-party on-system swaps (long contracts)

 

77

 

(9

)

Physical offsets to third-party on-system swap transactions (short contracts)

 

(77

)

21

 

 

 

 

 

 

 

Processing margin hedges — liquids (short contracts)

 

(18,200

)

(3,247

)

Processing margin hedges — gas (long contracts)

 

2,025

 

172

 

 

 

 

 

 

 

Storage swap transactions (short contracts)

 

(70

)

4

 

 

 

 

 

 

 

Liquid put options (purchased)

 

5,552

 

74

 

Total mark to market derivatives

 

 

 

$

(2,924

)

 


*                 All are gas contracts, volume in MMBtu’s, except for processing margin hedges — liquids and liquids swaps (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.

 

14



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

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, 2011 of $9.1 million would be reduced to $3.3 million due to the netting feature, all of which relates to other energy companies.

 

Impact of Cash Flow Hedges

 

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

 

 

 

Three Months Ended

 

 

 

March 31,

 

Increase (Decrease) in Midstream Revenue

 

2011

 

2010

 

Liquids

 

$

(660

)

$

(842

)

Realized loss included in Midstream revenue

 

$

(660

)

$

(842

)

 

Natural Gas

 

As of March 31, 2011, the Partnership has no balances in accumulated other comprehensive income related to natural gas.

 

Liquids

 

As of March 31, 2011, an unrealized derivative fair value net loss of $1.9 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive loss. Of this net amount, an approximate loss of  $1.7 million is expected to be reclassified into earnings through March 2012. 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 amount is not reflected above.

 

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 put options purchased 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 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, 2011

 

$

(2,809

)

$

(115

)

$

 

$

(2,924

)

 

(8)      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.

 

15



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

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, 2011

 

December 31, 2010

 

 

 

Level 2

 

Level 2

 

Commodity Swaps*

 

$

(5,017

)

$

(2,444

)

Total

 

$

(5,017

)

$

(2,444

)

 


*                 Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income at each measurement date.

 

(9)      Fair Value of Financial Instruments

 

The estimated fair value of the Company’s financial instruments has been determined by the Company 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 Company could realize upon the sale or refinancing of such financial instruments (in thousands).

 

 

 

March 31, 2011

 

December 31, 2010

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

 

 

Value

 

Value

 

Value

 

Value

 

Fair value of derivative assets

 

$

6,024

 

$

6,024

 

$

6,692

 

$

6,692

 

Long-term debt

 

735,044

 

810,589

 

718,570

 

768,308

 

Obligations under capital lease

 

30,600

 

28,697

 

31,327

 

28,807

 

Fair value of derivative liabilities

 

11,041

 

11,041

 

9,136

 

9,136

 

 

The carrying amounts of the Company’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 $16.0 million in borrowings under its revolving credit facility included in long-term debt as of March 31, 2011 and no borrowing at December 31, 2010 and accrued interest under floating interest rate structures. Accordingly, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of March 31, 2011 and December 31, 2010, the Partnership also had borrowings totaling $712.0 million and $711.5 million, respectively, under senior unsecured notes with a fixed rate of 8.875% and a series B secured note with a principal amount of $7.1 million and $7.1 million, respectively, with a fixed rate of 9.5%. The fair value of the senior unsecured notes as of March 31, 2011 and December 31, 2010 was based on third party market quotations. The fair values of the series B secured note as of March 31, 2011 and December 31, 2010 were adjusted to reflect current market interest rates for such borrowings on the applicable 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 adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.

 

16



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

(10) Income Tax

 

The Company has recorded a deferred tax asset in the amount of $20.5 million relating to the difference between its book and tax basis of its investment in the Partnership as of March 31, 2011 and December 31, 2010.  Because the Company can only realize this deferred tax asset upon the liquidation of the Partnership and to the extent of capital gains, the Company has provided a full valuation allowance against this deferred tax asset. There was no change in the deferred tax asset or the related valuation allowance during the first quarter of 2011. The income tax provision for the three months ended March 31, 2011 reflects a tax benefit of $ 0.7 million for the current period. Unrecognized tax benefits increased $0.1 million during the three months ended March 31, 2011, and the increase, if recognized, would affect the effective tax rate.

 

(11) Commitments and Contingencies

 

(a) Employment Agreements

 

Certain members of management of the Company are parties to employment contracts with the general partner of the Partnership. The employment agreements provide those senior managers with severance payments in certain circumstances and prohibit each such person from competing with the general partner of the Partnership 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. In addition, the Partnership has disclosed possible Clean Air Act monitoring deficiencies it has discovered to the Louisiana Department of Environmental Quality (LDEQ) and is working with the department to correct these deficiencies and to address modifications to facilities to bring them into compliance. The Partnership does not expect to incur any material environmental liability associated with these issues.

 

(c) Other

 

The Company 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 alleged receipt by the plaintiffs of natural gas liquids into their facilities from facilities operated by the Partnership.  The lawsuit alleges that the plaintiffs have incurred at least $65.0 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.

 

17



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

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. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not believe that these claims will have a material adverse impact on its consolidated results of operations or financial condition.

 

(12) Segment Information

 

In 2010, the Partnership’s management realigned the composition of its segments. Accordingly, the Partnership has recast its segment information for prior periods to reflect this new alignment.

 

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 (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 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 principally of property and equipment, including software, for general corporate support, working capital and debt financing costs.

 

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, 2011:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

204,433

 

$

80,966

 

$

164,916

 

$

 

$

450,315

 

Sales to affiliates

 

22,807

 

$

21,585

 

$

 

$

(44,392

)

$

 

Purchased gas and NGLs

 

(195,503

)

$

(63,159

)

$

(146,208

)

$

44,392

 

$

(360,478

)

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

 

$

(3,161

)

$

(17,720

)

$

(7,713

)

$

(1,078

)

$

(29,672

)

Capital expenditures

 

$

1,550

 

$

18,203

 

$

4,083

 

$

487

 

$

24,323

 

Identifiable assets

 

$

324,924

 

$

1,110,852

 

$

489,147

 

$

39,670

 

$

1,964,593

 

Three Months Ended March 31, 2010:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

245,358

 

$

110,134

 

$

113,166

 

$

 

$

468,658

 

Sales to affiliates

 

21,714

 

25,791

 

1,531

 

(49,036

)

 

Purchased gas and NGLs

 

(239,295

)

(98,298

)

(98,906

)

49,036

 

(387,463

)

Operating expenses

 

(8,459

)

(12,052

)

(5,954

)

 

(26,465

)

Segment profit

 

$

19,318

 

$

25,575

 

$

9,837

 

$

 

$

54,730

 

Loss on derivatives

 

$

(1,810

)

$

(1,814

)

$

(72

)

$

 

$

(3,696

)

Depreciation, amortization and impairments

 

$

(3,039

)

$

(16,056

)

$

(7,895

)

$

(1,118

)

$

(28,108

)

Capital expenditures

 

$

930

 

$

2,688

 

$

69

 

$

415

 

$

4,102

 

Identifiable assets

 

$

346,975

 

$

1,145,897

 

$

488,641

 

$

49,760

 

$

2,031,273

 

 

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

 

18



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

Segment profits

 

$

64,793

 

$

54,730

 

General and administrative expenses

 

(12,481

)

(13,481

)

Loss on derivatives

 

(3,421

)

(3,696

)

Gain on sale of property

 

19

 

14,343

 

Depreciation, amortization and impairments

 

(29,672

)

(28,108

)

Operating income

 

$

19,238

 

$

23,788

 

 

(13) Subsequent Event

 

In May 2011, the Partnership amended its bank credit facility. The borrowing capacity under the credit facility has been increased from $420.0 million to $485.0 million and the maturity was extended from February 2014 to May 2016. Additionally, the amendment to the Partnership’s credit facility, among other things, (i) increased the maximum permitted leverage ratios during certain fiscal quarters and (ii) decreased the interest rate the Partnership pays on the obligations under the credit facility. Also under the amended credit facility, the Partnership increased the accordian from $100.0 million to $150.0 million, which permits it to increase the Partnership’s borrowing base if any bank in the credit facility or a new bank is willing to undertake such commitment.

 

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.

 

Under the amended credit facility, borrowings bear interest at the Partnership’s option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. The Partnership pays a per annum fee (as described below) on all letters of credit issued under the amended credit facility and a commitment fee of between 0.375% and 0.50% per annum on the unused availability under the amended credit facility. The commitment fee, letter of credit fee and the applicable margins for the interest rate vary quarterly based on the Partnership’s leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:

 

 

 

Base Rate

 

Eurodollar 
Rate

 

Letter of 
Credit

 

Leverage Ratio 

 

Loans

 

Loans

 

Fees

 

Greater than or equal to 4.50 to 1.00

 

2.00

%

3.00

%

3.00

%

Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00

 

1.75

%

2.75

%

2.75

%

Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00

 

1.50

%

2.50

%

2.50

%

Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00

 

1.25

%

2.25

%

2.25

%

Less than 3.00 to 1.00

 

1.00

%

2.00

%

2.00

%

 

The amended credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter.

 

The maximum permitted leverage ratio is as follows:

 

·                       5.00 to 1.00 for the fiscal quarter ending March 31, 2011 and June 30, 2011;

 

·                       4.75 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements-(Continued)

 

The maximum permitted senior leverage ratio (as defined in the credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges), is 2.75 to 1.00.

 

All other material terms of the credit facility are described in our Annual Report on Form 10-K for the year ended December 31, 2010. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

 

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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

 

Crosstex Energy, Inc. is a Delaware corporation formed on April 28, 2000 to engage in the gathering, transmission, processing and marketing of natural gas and natural gas liquids (NGLs) through its subsidiaries. Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, processing, transmission and marketing of natural gas and NGLs.  These partnership interests consist of (i) 16,414,830 common units, representing approximately 25.0% of the limited partner interests in Crosstex Energy, L.P., and (ii) 100% ownership interest in Crosstex Energy GP, LLC, the general partner of Crosstex Energy, L.P., which owns a 2.0% general partner interest and all of the incentive distribution rights in Crosstex Energy, L.P.

 

Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership’s business or to provide for future distributions.

 

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries.  We have no separate operating activities apart from those conducted by the Partnership, and our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own.  Our consolidated results of operations are derived from the results of operations of the Partnership and also include our deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operation.  Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership.

 

The Partnership’s primary focus is on the gathering, processing, transmission and marketing of NGLs, which it manages in regional reporting segments of midstream activity.  The Partnership’s geographic focus is in the north Texas Barnett Shale (NTX) and in Louisiana which has two reportable business segments (LIG system and the south Louisiana processing and NGL assets, or PNGL). The Partnership manages its operations by focusing on gross operating margin because its 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. We define gross operating margin as operating revenue minus cost of purchased gas and NGLs.

 

The Partnership’s gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities, and the volumes of NGLs handled at its fractionation facilities. The Partnership generates revenues from four primary sources:

 

·                  purchasing and reselling or transporting natural gas on the pipeline systems it owns;

 

·                  processing natural gas at its processing plants;

 

·                  fractionating and marketing the recovered NGLs; and

 

·                  providing compression services.

 

The Partnership generally gathers or transports gas owned by others through its facilities for a fee, or it buys 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 transports and resells the natural gas at the market index. The Partnership attempts to execute all purchases and sales substantially concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction.  The Partnership’s gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas.  The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that it has under contract may decline due to reduced drilling or other causes and the Partnership may be required to satisfy the sales obligations by buying additional gas at prices that may

 

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exceed the prices received under the sales commitments. In the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, on occasion the Partnership has 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 it captures the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as margin. Changes in the basis spread can increase or decrease margins.

 

One contract (the “Delivery Contract”) has a term to 2019 that obligates the Partnership to supply approximately 150,000 MMBtu/d of gas.  At the time that the Partnership entered into the Delivery Contract in 2008, it had dedicated supply sources in the Barnett Shale that exceeded the delivery obligations under the Delivery Contract.  The Partnership’s agreements with these suppliers generally provided that the purchase price for the gas was equal to a portion of its sales price for such gas less certain fees and costs.  Accordingly, the Partnership was 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 the 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, the Partnership has had to purchase a portion of the gas to fulfill its obligations under the Delivery Contract at market prices, resulting in negative margins under the Delivery Contract.

 

The Partnership has recorded a loss of approximately $3.0 million during the three months ended March 31, 2011 on the Delivery Contract.  The Partnership currently expects that it will record a loss of approximately $10.0 million to $14.0 million on the Delivery Contract for the year ending December 31, 2011.  This estimate is based on forward prices, basis spreads and other market assumptions as of March 31, 2011. These assumptions are subject to change if market conditions change during the remainder of 2011, and actual results under the Delivery Contract in 2011 could be substantially different from the Partnership’s current estimates, which may result in a greater loss than currently estimated.

 

The Partnership also realizes gross operating margins from its processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fixed-fee based. Under margin contract arrangements the Partnership’s 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 the Partnership’s 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.

 

Recent Developments

 

Credit Facility. On May 2, 2011, the Partnership amended its bank credit facility.  This amendment increased its borrowing capacity from $420.0 million to $485.0 million, reduced its interest rates and improved terms of other covenants under the facility. See Note (13) to the condensed consolidated financial statements for a discussion of the amended terms.

 

Asset Expansions.  The Partnership completed two expansion projects on its natural gas gathering system in the Barnett Shale play in North Texas that the Partnership expects will make a major contribution to gathered volumes. The Partnership also reactivated its Eunice natural gas liquids (NGL) fractionators in south central Louisiana, which will give the Partnership operational flexibility, increased fractionation capacity and the ability to capture new NGL-related business. The two North Texas projects became operational in late March 2011 and the Eunice NGL fractionator became operational  in early April 2011.

 

The Partnership expanded its natural gas gathering system in North Texas with the construction of a $25.0 million, 15-mile pipeline extension to serve major Barnett Shale producers.  The project, which is supported by volumetric commitments, includes a seven-mile low-pressure pipeline, an eight-mile high-pressure pipeline and a compressor station in southwest Tarrant County that provides customers with greater takeaway capacity to accommodate their transportation requirements.

 

The Partnership also entered into a 10-year firm gathering and compression agreement with a major Barnett Shale producer for an additional 50 MMcf/d on its North Texas gathering system.  The Partnership constructed a compressor station on an existing gathering line to accommodate the customer’s transportation requirements.

 

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In south central Louisiana, the Partnership’s Eunice NGL fractionator was reactivated with the necessary equipment to accommodate 15,000 barrels of NGLs per day (“Bbls/d”).  Additional capacity of 21,000 Bbls/d can be restarted as supplies grow. The Eunice start-up and expansion project increased the Partnership’s fractionation capacity for liquids products from 40,000 Bbls/d to 55,000 Bbls/d.

 

Non-GAAP Financial Measures

 

We include the following non-GAAP financial measures: The Partnership’s adjusted EBITDA and gross operating margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with generally accepted accounting principles, or GAAP.

 

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

 

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

 

·                  the ability of the Partnership’s assets to generate cash sufficient to pay interest costs, support its indebtedness and make cash distributions to its unitholders and the general partner;

 

·                  the Partnership’s 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.

 

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

 

The Partnership’s 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. The 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.

 

The Partnership’s adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because the Partnership has borrowed money to finance its operations, interest expense is a necessary element of its costs and its ability to generate cash available for distribution. Because the Partnership uses capital assets, depreciation and amortization are also necessary elements of its 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 the Partnership’s adjusted EBITDA, to evaluate the Partnership’s overall performance.

 

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Table of Contents

 

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

 

 

 

Three Months Ended March 31,

 

 

 

2011

 

2010

 

 

 

(In millions)

 

 

 

 

 

 

 

Net income (loss)

 

$

(1.5

)

$

(5.4

)

Interest expense

 

19.8

 

26.9

 

Depreciation and amortization

 

29.7

 

27.1

 

Impairment

 

 

1.0

 

Loss on extinguishment of debt

 

 

14.7

 

Gain on sale of property

 

 

(14.3

)

Stock-based compensation

 

2.3

 

2.6

 

Minority interest

 

1.8

 

(9.6

)

Taxes

 

(0.6

)

(2.6

)

Other (a)

 

2.1

 

3.4

 

Adjusted EBITDA

 

$

53.6

 

$

43.8

 

 


(a)  Includes the Partnership’s financial derivatives marked-to-market and CEI’s direct general and administrative expenses and other income that are not included in the Partnership’s adjusted EBITDA.

 

We define gross operating margin, generally, as revenues minus cost of sales. The Partnership presents 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 the Partnership’s 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 the Partnership’s operating expenses. These expenses are largely independent of the volumes the Partnership transports or processes and fluctuates depending on the activities performed during a specific period. The Partnership does not deduct operating expenses from total revenue in calculating gross operating margin because the Partnership separately evaluate commodity volume and price changes in these margin amounts. As an indicator of the Partnership’s operating performance, gross operating margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. The Partnership’s 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 the Partnership’s gross operating margin to operating income:

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

 

 

(In millions)

 

Total gross operating margin

 

$

89.8

 

$

81.2

 

 

 

 

 

 

 

Add (deduct):

 

 

 

 

 

Operating expenses

 

(25.0

)

(26.5

)

General and administrative expenses

 

(12.5

)

(13.5

)

Gain on sale of property

 

 

14.3

 

Loss on derivatives

 

(3.4

)

(3.7

)

Depreciation, amortization and impairments

 

(29.7

)

(28.1

)

Operating income

 

$

19.2

 

$

23.7

 

 

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Table of Contents

 

Results of Operations

 

Set forth in the table below is certain financial and operating data for the periods indicated. The Partnership manages its operations by focusing on gross operating margin which the Partnership defines as operating revenue minus cost of purchased gas and NGLs as reflected in the table below.

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

 

 

(Dollars in millions)

 

LIG Segment

 

 

 

 

 

Revenues

 

$

227.2

 

$

267.1

 

Purchased gas and NGLs

 

(195.5

)

(239.3

)

Total gross operating margin

 

$

31.7

 

$

27.8

 

NTX Segment

 

 

 

 

 

Revenues

 

$

102.6

 

$

135.9

 

Purchased gas and NGLs

 

(63.2

)

(98.3

)

Total gross operating margin

 

$

39.4

 

$

37.6

 

PNGL Segment

 

 

 

 

 

Revenues

 

$

164.9

 

$

114.7

 

Purchased gas and NGLs

 

(146.2

)

(98.9

)

Total gross operating margin

 

$

18.7

 

$

15.8

 

Corporate

 

 

 

 

 

Revenues

 

$

(44.4

)

$

(49.0

)

Purchased gas and NGLs

 

44.4

 

49.0

 

Total gross operating margin

 

$

 

$

 

Total

 

 

 

 

 

Revenues

 

$

450.3

 

$

468.7

 

Purchased gas and NGLs

 

(360.5

)

(387.5

)

Total gross operating margin

 

$

89.8

 

$

81.2

 

 

 

 

 

 

 

Midstream Volumes:

 

 

 

 

 

LIG

 

 

 

 

 

Gathering and Transportation (MMBtu/d)

 

938,000

 

916,000

 

Processing (MMBtu/d)

 

258,000

 

284,000

 

NTX

 

 

 

 

 

Gathering and Transportation (MMBtu/d)

 

1,054,000

 

1,081,000

 

Processing (MMBtu/d)

 

214,000

 

200,000

 

PNGL

 

 

 

 

 

Processing (MMBtu/d)

 

921,000

 

928,000

 

NGL Fractionation (Gals/d)

 

1,132,000

 

937,000

 

 

 

 

 

 

 

Commercial Services (MMBtu/d)

 

220,000

 

52,000

 

 

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

 

Gross Operating Margin. Gross operating margin was $89.8 million for the quarter ended March 31, 2011 compared to $81.2 million for the three months ended March 31, 2010, an increase of $8.6 million, or 10.6%. The increase was due to higher margins on the Partnership’s gathering and transmission throughput volume, as well as a favorable NGL market throughout the quarter. The following provides additional details regarding this change in gross operating margin:

 

·                        The LIG segment contributed gross operating margin growth of $3.9 million for the three months ended March 31, 2011 compared to the three months ended March 31, 2010. The gathering and transmission assets generated approximately $3.1 million of gross operating margin growth primarily due to improved pricing and higher volumes on the northern part of the system. The improved processing environment contributed to a gain in the gross operating margins for the LIG processing plants for the period.  The Plaquemine and Gibson plants combined for a gross operating margin gain of $0.8 million.

 

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Table of Contents

 

·                        The NTX segment had gross operating margin improvement of $1.8 million for the three months ended March 31, 2011 compared to the three months ended March 31, 2010. A gross operating margin increase of $3.9 million on the gathering and transmission assets in north Texas was offset by increased losses of $2.1 million on the Delivery Contract discussed previously.

 

·                        The improved processing and NGL marketing environment contributed to a $2.9 million increase in gross operating margin for the PNGL segment for the three months ended March 31, 2011 compared to the three months ended March 31, 2010.  Fractionation and marketing activity generated a gross operating margin increase of approximately $1.8 million.  In addition to the improved marketing environment, the inlet volume supplied to the fractionators was significantly increased through deliveries from rail cars and trucks.  The Blue Water processing plant contributed a gross operating margin increase of $1.1 million due to an increase in plant run time and inlet volumes.

 

Operating Expenses. Operating expenses were $25.0 million for the three months ended March 31, 2011 compared to $26.5 million for the three months ended March 31, 2010, a decrease of $1.4 million, or 5.4%. The decrease is primarily due to normal fluctuations of repair and maintenance work during the three months ended March 31, 2011 compared to three months ended March 31, 2010.

 

General and Administrative Expenses. General and administrative expenses were $12.5 million for the three months ended March 31, 2011 compared to $13.5 million for the three months ended March 31, 2010, a decrease of $1.0 million, or 7.4%. The decrease is primarily due to a decrease in professional fees and services.

 

Gain on Sale of Property.  Assets sold during the three months ended March 31, 2010 generated a net gain of $14.3 million, resulting primarily from the sale of the east Texas assets.

 

Gain/Loss on Derivatives. The Partnership had a loss on derivatives of $3.4 million for the three months ended March 31, 2011 compared to a loss of $3.7 million for the three months ended March 31, 2010. The derivative transaction types contributing to the net (gain) loss are as follows (in millions):

 

 

 

Three Months Ended March 31,

 

 

 

2011

 

2010

 

 

 

Total

 

Realized

 

Total

 

Realized

 

Basis swaps

 

$

0.6

 

$

0.8

 

$

2.1

 

$

(0.5

)

Processing margin hedges

 

2.7

 

1.2

 

1.8

 

1.9

 

Other

 

0.1

 

(0.2

)

(0.2

)

 

Net losses related to commodity swaps

 

$

3.4

 

$

1.8

 

$

3.7

 

$

1.4

 

 

Depreciation and Amortization. Depreciation and amortization expenses were $29.7 million for the three months ended March 31, 2011 compared to $27.1 million for the three months ended March 31, 2010, an increase of $2.6 million, or 9.6%. The increase is primarily due to intangible amortization related to downward revision in future throughput volumes attributable to the gathering system in north Texas.

 

Interest Expense. Interest expense was $19.8 million for the three months ended March 31, 2011 compared to $26.9 million for the three months ended March 31, 2010, a decrease of $7.1 million, or 26.4%. Net interest expense consists of the following (in millions):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Senior notes (secured and unsecured)

 

$

16.6

 

$

12.8

 

Paid-in-kind interest on senior secured notes

 

 

1.4

 

Bank credit facility

 

1.3

 

5.7

 

Mark to market interest rate swaps

 

 

(22.4

)

Realized interest rate swap losses

 

 

26.5

 

Amortization of debt issue costs

 

1.6

 

2.1

 

Other

 

0.3

 

0.8

 

Total

 

$

19.8

 

$

26.9

 

 

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Loss on Extinguishment of Debt. The Partnership recognized a loss on extinguishment of debt during the three months ended March 31, 2010 of $14.7 million.  In February 2010, the Partnership repaid its existing credit facility and senior secured notes which resulted in make-whole interest payments on its senior secured notes and the write-off of unamortized debt costs totaling $14.7 million.

 

Income Taxes.  Income tax benefit was $ 0.7 million for the three months ended March 31, 2011 compared to $ 2.6 million for the three months ended March 31, 2010, resulting from net losses during each of these periods.

 

Interest of Non-Controlling Partners in the Partnership’s Net Income (Loss).  The interest of non-controlling partners in the Partnership’s net income was $1.8 million for the three months ended March 31, 2011 compared to a net loss of $9.6 million for the three months ended March 31, 2010 due to the changes shown in the following summary (in millions):

 

 

 

Three Months Ended March 31,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Net income (loss) for the Partnership

 

$

0.1

 

$

(17.4

)

Income allocation to CEI for the general partner incentive distribution

 

(0.4

)

 

Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors

 

0.9

 

1.1

 

Loss allocation to CEI for its 2% general partner share of Partnership loss

 

 

0.4

 

Net income (loss) allocable to limited partners

 

0.6

 

(15.9

)

Less: CEI’s share of net income allocable to limited partners

 

(1.2

)

(6.3

)

Non-controlling partners’ share of Partnership net income (loss)

 

$

1.8

 

$

(9.6

)

 

Critical Accounting Policies

 

Information regarding the Partnership’s Critical Accounting Policies is included in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

 

Liquidity and Capital Resources

 

Cash Flows from Operating Activities. Net cash provided by operating activities was $1.7 million for the three months ended March 31, 2011 compared to net cash used in operating activities of $25.3 million for three months ended March 31, 2010. Income before non-cash income and expenses and changes in working capital for comparative periods were as follows (in millions):

 

 

 

Three Months Ended

 

 

 

March  31,

 

 

 

2011

 

2010

 

 

 

 

 

 

 

Income before non-cash income and expenses

 

$

34.7

 

$

(27.6

)

Changes in working capital

 

$

(33.0

)

$

2.3

 

 

The primary reason for the increase in cash flow from income before non-cash income and expenses of $62.3 million from 2010 to 2011 relates to payments in 2010 for settlements of interest rate swaps, make-whole payments, and PIK  notes associated with the extinguishment of debt combined with an increase in gross margin and a decrease in interest expense between the first quarter of 2011 as compared to the first quarter of 2010.

 

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Cash Flows from Investing Activities. Net cash used in investing activities was $21.5 million for the three months ended March 31, 2011 and net cash provided by investing activities was $30.9 million for the three months ended March 31, 2010. Cash flows from investing activities for the three months ended March 31, 2010 includes proceeds from property sales of $39.7 million related to the sale of east Texas assets. The Partnership’s primary investing outflows were capital expenditures, net of accrued amounts, as follows (in millions):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

Growth capital expenditures

 

$

19.2

 

$

7.5

 

Maintenance capital expenditures

 

2.4

 

2.2

 

Total

 

$

21.6

 

$

9.7

 

 

Cash Flows from Financing Activities. Net cash provided by financing activities was $2.9 million for the three months ended March 31, 2011 and net cash used in financing activities was $9.7 million for the three months ended March 31, 2010. The Partnership’s financings have primarily consisted of repayments under the bank credit facilities, repayments under capital lease obligations, senior secured note repayments, senior unsecured note borrowings and debt refinancing costs.

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

Net borrowings (repayments) under bank credit facilities

 

$

16.0

 

$

(491.6

)

Senior secured note repayments

 

 

(316.5

)

Senior unsecured note borrowings (net of discount on the note)

 

 

709.8

 

Net repayments under capital lease obligations

 

(0.7

)

(0.6

)

Debt refinancing costs

 

(0.1

)

(28.1

)

 

Dividends to shareholders and distributions to non-controlling partners in the Partnership represents one of our primary uses of cash in financing activities. No dividends or cash distributions were paid during the three months ended March 31, 2010.  Total cash dividends and distributions made during the three months ended March 31, 2011 were as follows (in millions):

 

 

 

Three Months 
Ended

 

 

 

March 31,

 

 

 

2011

 

Dividend to shareholders

 

$

3.8

 

Non-controlling partner distributions

 

12.9

 

Total

 

$

16.7

 

 

In order to reduce our interest costs, the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on the Partnership’s revolving credit facility. The Partnership borrows money under its credit facility to fund checks as they are presented. As of March 31, 2011, the Partnership had approximately $330.8 million of available borrowing capacity under this facility. Changes in drafts payable for the three months ended 2011 and 2010 were as follows (in millions):

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

Increase (decrease) in drafts payable

 

$

6.3

 

$

(1.6

)

 

Working Capital Deficit.  We had a working capital deficit of $8.0 million as of March 31, 2011.  Changes in working capital may fluctuate significantly between periods even though the Partnership’s trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles.  A large volume of the Partnership’s revenues are collected and a large volume of its gas purchases are paid near each month end or the first few days of the following month so receivable and payable balances at any month end may fluctuate significantly depending on the timing of these receipts and payments.  In addition, although the Partnership strives to minimize its natural gas and NGLs in inventory, these working inventory balances may fluctuate significantly from period to period due to operational reasons and due to changes in natural gas and NGL prices. Working capital also includes mark to market derivative assets and liabilities associated with commodity derivatives which may fluctuate significantly due to the changes in natural gas and NGL prices.

 

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Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of March 31, 2011.

 

Capital Requirements. During the three months ended March 31, 2011, the Partnership’s growth capital investments were $19.2 million, which were funded by internally generated cash flow and from borrowings under its credit facility. The Partnership’s current capital spending projection for 2011 is approximately $50.0 million related to identified growth projects including $19.2 million incurred during the first quarter of 2011. The Partnership may identify more growth projects during 2011 in addition to projects currently budgeted.

 

Total Contractual Cash Obligation. A summary of the Partnership’s contractual cash obligation as of March 31, 2011, is as follows (in millions):

 

 

 

Payments Due by Period

 

 

 

Total

 

2011

 

2012

 

2013

 

2014

 

2015

 

Thereafter

 

Long-term debt obligations

 

$

732.1

 

$

7.1

 

$

 

$

 

$

 

$

 

$

725.0

 

Bank credit facility

 

16.0

 

 

 

 

 

 

16.0

 

Interest payable on fixed long-term debt obligations

 

449.7

 

32.5

 

64.3

 

64.3

 

64.3

 

64.3

 

160.0

 

Capital lease obligations

 

38.4

 

3.4

 

4.6

 

4.6

 

4.6

 

4.6

 

16.6

 

Operating lease obligations

 

38.4

 

7.3

 

10.5

 

6.8

 

5.0

 

3.7

 

5.1

 

Purchase obligations

 

4.6

 

4.6

 

 

 

 

 

 

Uncertain tax position obligations

 

3.8

 

3.8

 

 

 

 

 

 

Total contractual obligations

 

$

1,283.0

 

$

58.7

 

$

79.4

 

$

75.7

 

$

73.9

 

$

72.6

 

$

922.7

 

 

The above table does not include any physical or financial contract purchase commitments for natural gas due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

 

Indebtedness

 

As of March 31, 2011 and December 31, 2010, long-term debt consisted of the following (in millions):

 

 

 

March 31,

 

December 31,

 

 

 

2011

 

2010

 

Bank credit facility (due 2016), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at March 31, 2011 and December 31, 2010 was 4.75% and 4.0%, respectively

 

$

16.0

 

$

 

Senior unsecured notes (due 2018), net of discount of $13.0 million and $13.5 million, respectively, which bear interest at the rate of 8.875%

 

712.0

 

711.5

 

Series B secured note assumed in the Eunice transaction (due 2011), which bears interest at the rate of 9.5%

 

7.1

 

7.1

 

 

 

735.1

 

718.6

 

Less current portion

 

(7.1

)

(7.1

)

Debt classified as long-term

 

$

728.0

 

$

711.5

 

 

Credit Facility. As of March 31, 2011, the Partnership’s bank credit facility had a borrowing capacity of $420.0 million and there was $73.2 million in letters of credit issued and outstanding under the bank credit facility and $16.0 million of borrowings outstanding, leaving approximately $330.8 million available for future borrowing. The bank credit facility is guaranteed by substantially all of the Partnership’s subsidiaries. The bank credit facility matures in February 2014.

 

On May 2, 2011, the Partnership amended its bank credit facility.  This amendment increased its borrowing capacity from $420.0 million to $485.0 million, reduced its interest rates and improved terms of other covenants under the facility.  See Note (13) to the condensed consolidated financial statement for a discussion of the amended terms.

 

Recent Accounting Pronouncements

 

In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-06, Improving Disclosures about Fair Value Measurements, which amends FASB ASC Topic 820, Fair Value Measurements and Disclosures. The ASU requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information about purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. The ASU also clarifies existing fair-value measurement disclosure guidance about the level of disaggregation, inputs, and valuation techniques. We have evaluated the ASU and determined that we are not currently impacted by the update.

 

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Disclosure Regarding Forward-Looking Statements

 

This Quarterly Report on Form 10-Q includes forward-looking statements. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Such statements reflect our current views with respect to future events based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to specific uncertainties discussed elsewhere in this Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, and those set forth in Part II, “Item 1A. Risk Factors” of this report, if any, may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

 

Item 3. Quantitative and Qualitative Disclosures about Market Risk

 

Market risk is the risk of loss arising from adverse changes in market rates and prices. The Partnership’s primary market risk is the risk related to changes in the prices of natural gas and NGLs. In addition, it is exposed to the risk of changes in interest rates on its floating rate debt.

 

On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”) into law, a part of which relates to increased regulation of the markets for derivative products of the type the Partnership uses to manage areas of market risk. While the Commodity Futures Trading Commission has yet to issue regulations to implement this increased regulation, Dodd-Frank may result in increased costs to the Partnership to implement its market risk management strategy.

 

Interest Rate Risk

 

The Partnership is exposed to interest rate risk on its variable rate bank credit facility. At March 31, 2011, the Partnership had $16.0 million in borrowings under this facility. A 1% increase or decrease in interest rates would not materially impact the interest expense on this borrowing.

 

At March 31, 2011, the Partnership had total fixed rate debt obligations of $719.0 million, consisting of its senior unsecured notes with an interest rate of 8.875% and a series B secured note with an interest rate of 9.5%. The fair value of these fixed rate obligations was approximately $810.6 million as of March 31, 2011. The Partnership estimates that a 1% increase or decrease in interest rates would increase or decrease the fair value of such debt by $29.6 million.

 

Commodity Price Risk

 

The Partnership is subject to significant risks due to fluctuations in commodity prices. Its exposure to these risks is primarily in the gas processing component of its business. The Partnership currently processes gas under three main types of contractual arrangements:

 

1.                    Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and  makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR. The Partnership’s margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership mitigates its risk of processing natural gas when margins are negative primarily through its ability to bypass processing when it is not profitable for the Partnership, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

 

2.                    Percent of liquids contracts: Under these contracts, the Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, its margins from these contracts are greater during periods of high liquids prices. The Partnership’s margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.

 

3.                    Fee based contracts: Under these contracts the Partnership has no commodity price exposure and is paid a fixed fee per unit of volume that is processed.

 

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Table of Contents

 

Gas processing margins by contract types and gathering and transportation margins as a percent of total gross operating margin for the comparative year-to-date periods are as follows:

 

 

 

Three Months Ended

 

 

 

March 31,

 

 

 

2011

 

2010

 

Gathering and transportation margin

 

55.7

%

60.2

%

 

 

 

 

 

 

Gas processing margins:

 

 

 

 

 

Processing margin

 

17.9

%

13.4

%

Percent of liquids

 

12.2

%

13.7

%

Fee based

 

14.2

%

12.7

%

Total gas processing

 

44.3

%

39.8

%

 

 

 

 

 

 

Total

 

100.0

%

100.0

%

 

The Partnership has hedges in place at March 31, 2011 covering a portion of the liquids volumes it expects to receive under percent of liquids (POL) contracts. The hedges done via swaps are set forth in the following table.  The relevant payment index price is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).

 

 

 

 

 

Notional

 

The
Partnership 

 

The Partnership

 

Fair Value

 

Period

 

Underlying

 

Volume

 

Pays

 

Receives*

 

Asset/(Liability)

 

 

 

 

 

 

 

 

 

 

 

(In thousands)

 

April 2011 – December 2011

 

Ethane

 

71

(MBbls)

 

Index

 

$

0.4673

 

/gal

 

$

(509

)

April 2011 – December 2011

 

Propane

 

34

(MBbls)

 

Index

 

$

1.1866

 

/gal

 

(287

)

April 2011 – December 2011

 

Normal Butane

 

20

(MBbls)

 

Index

 

$

1.5602

 

/gal

 

(245

)

April 2011 – December 2011

 

Natural Gasoline

 

19

(MBbls)

 

Index

 

$

1.8227

 

/gal

 

(522

)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(1,563

)

 


*weighted average

 

 

 

 

 

Notional

 

The
Partnership

 

The Partnership

 

Fair Value

 

Period

 

Underlying

 

Volume

 

Pays

 

Receives*

 

Asset/(Liability)

 

 

 

 

 

 

 

 

 

 

 

(In thousands)

 

January 2012 – December 2012

 

Ethane

 

25

(MBbls)

 

Index

 

$

0.4975

 

/gal

 

$

(38

)

January 2012 – December 2012

 

Propane

 

63

(MBbls)

 

Index

 

$

1.2973

 

/gal

 

(122

)

January 2012 – December 2012

 

Normal Butane

 

34

(MBbls)

 

Index

 

$

1.6773

 

/gal

 

(191

)

January 2012 – December 2012

 

Natural Gasoline

 

25

(MBbls)

 

Index

 

$

2.2712

 

/gal

 

(179

)

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(530

)

 


*weighted average

 

In addition, the Partnership has hedges in place covering 132 MBbls of Ethane for the final two quarters of 2011 done via the purchase of puts.  The net fair value asset of the puts as of March 31, 2011 was less than $0.1 million.

 

The Partnership has hedged its exposure to declines in prices for NGL volumes produced for its account. The NGL volumes hedged, as set forth above, focus on  POL contracts. The Partnership hedges  POL exposure based on volumes it considers hedgeable (volumes committed under contracts that are long term in nature) versus total POL volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month to month processing options. The Partnership has hedged 76.3% of its hedgeable volumes at risk through December 2011 (31.7% of total volumes at risk through December 2011). The Partnership has also hedged 28.6% of its hedgeable volumes at risk for 2012 (12.6% of total volumes at risk for 2012).

 

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Table of Contents

 

The Partnership also has hedges in place at March 31, 2011 covering the fractionation spread risk related to its processing margin contracts as set forth in the following table:

 

 

 

 

 

Notional

 

 

 

The Partnership

 

Fair Value

 

Period

 

Underlying

 

Volume

 

The Partnership Pays

 

Receives

 

Asset/(Liability)

 

 

 

 

 

 

 

 

 

 

 

(In thousands)

 

April 2011–December 2011

 

Ethane

 

109

(MBbls)

 

Index

 

$

0.4869

 

/gal*

 

$

(680

)

April 2011–December 2011

 

Propane

 

74

(MBbls)

 

Index

 

$

1.1498

 

/gal*

 

(747

)

April 2011–December 2011

 

Iso Butane

 

4

(MBbls)

 

Index

 

$

1.4941

 

/gal*

 

(78

)

April 2011–December 2011

 

Normal Butane

 

43

(MBbls)

 

Index

 

$

1.5385

 

/gal*

 

(548

)

April 2011–December 2011

 

Natural Gasoline

 

42

(MBbls)

 

Index

 

$

1.9938

 

/gal*

 

(851

)

April 2011–December 2011

 

Natural Gas

 

4,447

(MMBtu/d)

 

$

4.4651

 

/MMBtu*

 

Index

 

80

 

 

 

 

 

 

 

 

 

 

 

 

$

(2,824

)

 


*weighted average

 

 

 

 

 

Notional

 

 

 

The Partnership

 

Fair Value

 

Period

 

Underlying

 

Volume

 

The Partnership Pays

 

Receives

 

Asset/(Liability)

 

 

 

 

 

 

 

 

 

 

 

(In thousands)

 

January 2012–June 2012

 

Ethane

 

28

(MBbls)

 

Index

 

$

0.4980

 

/gal*

 

$

(42

)

January 2012–June 2012

 

Propane

 

65

(MBbls)

 

Index

 

$

1.3069

 

/gal*

 

(123

)

January 2012–June 2012

 

Normal Butane

 

38

(MBbls)

 

Index

 

$

1.7626

 

/gal*

 

(89

)

January 2012–June 2012

 

Natural Gasoline

 

31

(MBbls)

 

Index

 

$

2.3854

 

/gal*

 

(90

)

January 2012–June 2012

 

Natural Gas

 

4,406

(MMBtu/d)

 

$

4.8834

 

/MMBtu*

 

Index

 

93

 

 

 

 

 

 

 

 

 

 

 

 

$

(251

)

 


*      weighted average

 

In relation to its fractionation spread risk, as set forth above, the Partnership has hedged 55.2% of its hedgeable liquids volumes at risk through December 31, 2011 (20.4% of total liquids volumes at risk) and 59.2% of the related hedgeable PTR volumes through December 31, 2011 (21.5% of total PTR volumes). The Partnership has also hedged 50.6% of its hedgeable liquids volumes at risk for the first six months of  2012 (18.8% of total liquids volumes at risk) and 61.3% of the related hedgeable PTR volumes for the first six months of 2012 (22.3% of total PTR volumes).

 

The Partnership is also subject to price risk to a lesser extent for fluctuations in natural gas prices with respect to a portion of its gathering and transport services. Approximately 8.9% of the natural gas the Partnership markets is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price.

 

Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves it with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

 

The Partnership’s primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a risk management committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by its risk management committee.

 

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Table of Contents

 

The use of financial instruments may expose the Partnership to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.

 

As of March 31, 2011, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $5.0 million. The aggregate effect of a hypothetical 10% increase in gas and NGL prices would result in an increase of approximately $3.4 million in the net fair value liability of these contracts as of March 31, 2011 to a net fair value liability of approximately $8.4 million.

 

Item 4. Controls and Procedures

 

(a) Evaluation of Disclosure Controls and Procedures

 

We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy, Inc. of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (March 31, 2011), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

 

(b) Changes in Internal Control Over Financial Reporting

 

There has been no change in our internal control over financial reporting that occurred in the three months ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

PART II—OTHER INFORMATION

 

Item 1. Legal Proceedings

 

We are 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 our financial position or results of operations.

 

For a discussion of certain litigation and similar proceedings, please refer to Note 11, “Commitments and Contingencies,” of the Notes to Condensed Consolidated Financial Statements, which is incorporated by reference herein.

 

Item 1A. Risk Factors

 

Information about risk factors for the three months ended March 31, 2011 does not differ materially from that set forth in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2010.

 

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Table of Contents

 

Item 6. Exhibits

 

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):

 

Number

 

 

Description

 

 

 

 

3.1

 

Amended and Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006).

3.2

 

Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated March 22, 2006, filed with the Commission on March 28, 2006).

3.3

 

Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).

3.4

 

Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).

3.5

 

Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).

3.6

 

Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).

3.7

 

Amendment No. 3 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of January 19, 2010 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010).

3.8

 

Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).

3.9

 

Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, file No. 000-50067).

3.10

 

Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).

3.11

 

Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).

3.12

 

Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of January 19, 2010 (incorporated by reference to Exhibit 3.2 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010, file No. 000-50067).

31.1*

 

Certification of the Principal Executive Officer.

31.2*

 

Certification of the Principal Financial Officer.

32.1*

 

Certification of the Principal Executive Officer and the Principal Financial Officer of the Company pursuant to 18 U.S.C. Section 1350.

 


*                      Filed herewith.

 

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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.

 

 

CROSSTEX ENERGY, INC.

 

 

 

By:

/s/ WILLIAM W. DAVIS

 

 

William W. Davis

 

 

Executive Vice President and Chief Financial Officer

 

 

May 6, 2011

 

 

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