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 June 30, 2004

OR

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

for the transition period from                   to                   

Commission file number: 000-50067

CROSSTEX ENERGY, L.P.

(Exact name of registrant as specified in its charter)

Delaware

16-1616605

(State of organization)

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

 

2501 CEDAR SPRINGS, SUITE 600
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 is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes  o    No  x

As of July 30, 2004, the Registrant had  8,747,326 common units and 9,334,000 subordinated units outstanding.

 




 

TABLE OF CONTENTS

Item

 

 

DESCRIPTION

 

Page

PART I—FINANCIAL INFORMATION

 

1.

FINANCIAL STATEMENTS

3

2.

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

20

3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

27

4.

CONTROLS AND PROCEDURES

30

PART II—OTHER INFORMATION

 

6.

EXHIBITS AND REPORTS ON FORM 8-K

31

 

GLOSSARY OF TERMS

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

/d—per day

MMBtu—million British thermal units

2




CROSSTEX ENERGY, L.P.
Consolidated Balance Sheets
(dollars in thousands)

 

 

June 30,
2004

 

December 31,
2003

 

 

 

(Unaudited)

 

(Restated)

 

Assets

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

$

738

 

 

 

$

166

 

 

Accounts receivable:

 

 

 

 

 

 

 

 

 

Trade

 

 

15,090

 

 

 

10,238

 

 

Accrued revenues

 

 

201,401

 

 

 

124,517

 

 

Imbalances

 

 

494

 

 

 

447

 

 

Related party

 

 

448

 

 

 

1,618

 

 

Note receivable

 

 

677

 

 

 

535

 

 

Other

 

 

2,445

 

 

 

2,588

 

 

Fair value of derivative assets

 

 

7,569

 

 

 

4,080

 

 

Prepaid expenses and other

 

 

4,926

 

 

 

1,979

 

 

Total current assets

 

 

233,788

 

 

 

146,168

 

 

Property and equipment:

 

 

 

 

 

 

 

 

 

Property and equipment

 

 

338,798

 

 

 

228,386

 

 

Accumulated depreciation

 

 

(33,374

)

 

 

(24,477

)

 

Property and equipment, net

 

 

305,424

 

 

 

203,909

 

 

Intangible assets, net

 

 

5,886

 

 

 

5,366

 

 

Goodwill, net

 

 

4,873

 

 

 

4,873

 

 

Investment in limited partnerships

 

 

410

 

 

 

2,560

 

 

Other assets, net

 

 

3,920

 

 

 

3,174

 

 

Total assets

 

 

$

554,301

 

 

 

$

366,050

 

 

Liabilities and Partners’ Equity

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

Drafts payable

 

 

$

26,983

 

 

 

$

10,446

 

 

Accounts payable

 

 

4,589

 

 

 

6,325

 

 

Accrued gas purchases

 

 

202,185

 

 

 

119,900

 

 

Accounts payable—related party

 

 

213

 

 

 

448

 

 

Accrued imbalances payable

 

 

1,558

 

 

 

212

 

 

Fair value of derivative liabilities

 

 

3,369

 

 

 

2,487

 

 

Current portion of long-term debt

 

 

50

 

 

 

50

 

 

Other current liabilities

 

 

21,021

 

 

 

10,872

 

 

Total current liabilities

 

 

259,968

 

 

 

150,740

 

 

Long-term debt

 

 

124,650

 

 

 

60,700

 

 

Deferred tax liability

 

 

13,224

 

 

 

 

 

Minority interest in subsidiary

 

 

2,419

 

 

 

 

 

Fair value of derivative liabilities

 

 

25

 

 

 

 

 

Partners’ equity:

 

 

 

 

 

 

 

 

 

Common unit-holders (8,747,326 and 8,716,000 units issued and outstanding at June 30, 2004 and December 31, 2003, respectively)

 

 

114,957

 

 

 

116,780

 

 

Subordinated unit-holders (9,334,000 units issued and outstanding at June 30, 2004 and December 31, 2003)

 

 

31,323

 

 

 

33,593

 

 

General partner interest (2% interest with 369,007 and 368,000 equivalent units outstanding at June 30, 2004 and December 31, 2003, respectively)

 

 

3,580

 

 

 

2,854

 

 

Accumulated other comprehensive income

 

 

4,155

 

 

 

1,383

 

 

Total partners’ equity

 

 

154,015

 

 

 

154,610

 

 

Total liabilities and partners’ equity

 

 

$

554,301

 

 

 

$

366,050

 

 

 

See accompanying notes to consolidated financial statements.

3




CROSSTEX ENERGY, L.P.
Consolidated Statements of Operations
(In thousands, except per unit amounts)
(Unaudited)

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

       2004       

 

       2003       

 

       2004       

 

       2003       

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Midstream

 

 

$

507,744

 

 

 

$

224,030

 

 

 

$

825,957

 

 

 

$

469,345

 

 

Treating

 

 

7,568

 

 

 

5,222

 

 

 

14,712

 

 

 

10,477

 

 

Total revenues

 

 

515,312

 

 

 

229,252

 

 

 

840,669

 

 

 

479,822

 

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Midstream purchased gas

 

 

485,212

 

 

 

214,071

 

 

 

788,088

 

 

 

451,479

 

 

Treating purchased gas

 

 

1,487

 

 

 

2,035

 

 

 

2,863

 

 

 

4,451

 

 

Operating expenses

 

 

10,316

 

 

 

3,335

 

 

 

16,529

 

 

 

6,545

 

 

General and administrative

 

 

4,741

 

 

 

1,891

 

 

 

8,332

 

 

 

3,391

 

 

Stock based compensation

 

 

269

 

 

 

568

 

 

 

478

 

 

 

3,072

 

 

Profit on energy trading activities

 

 

(826

)

 

 

(738

)

 

 

(1,246

)

 

 

(845

)

 

(Gain) loss on sale of property

 

 

(22

)

 

 

 

 

 

274

 

 

 

 

 

Depreciation and amortization

 

 

5,921

 

 

 

2,611

 

 

 

10,339

 

 

 

5,046

 

 

Total operating costs and expenses

 

 

507,098

 

 

 

223,773

 

 

 

825,657

 

 

 

473,139

 

 

Operating income

 

 

8,214

 

 

 

5,479

 

 

 

15,012

 

 

 

6,683

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 

 

(2,186

)

 

 

(465

)

 

 

(3,341

)

 

 

(875

)

 

Other

 

 

112

 

 

 

(39

)

 

 

204

 

 

 

(1

)

 

Total other income (expense)

 

 

(2,074

)

 

 

(504

)

 

 

(3,137

)

 

 

(876

)

 

Income before minority interest and income tax

 

 

6,140

 

 

 

4,975

 

 

 

11,875

 

 

 

5,807

 

 

Minority interest in subsidiary

 

 

(70

)

 

 

 

 

 

(99

)

 

 

 

 

Net income before income tax

 

 

6,070

 

 

 

4,975

 

 

 

11,776

 

 

 

5,807

 

 

Income tax expense

 

 

(129

)

 

 

 

 

 

(129

)

 

 

 

 

Net income

 

 

$

5,941

 

 

 

$

4,975

 

 

 

$

11,647

 

 

 

$

5,807

 

 

General partner interest in net income

 

 

$

1,393

 

 

 

$

155

 

 

 

$

2,442

 

 

 

$

172

 

 

Limited partners’ interest in net income

 

 

$

4,548

 

 

 

$

4,820

 

 

 

$

9,205

 

 

 

$

5,635

 

 

Net income per limited partners’ unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

$

0.25

 

 

 

$

0.33

 

 

 

$

0.51

 

 

 

$

0.39

 

 

Diluted

 

 

$

0.24

 

 

 

$

0.32

 

 

 

$

0.48

 

 

 

$

0.38

 

 

Weighted average limited partners’ units outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

18,081

 

 

 

14,600

 

 

 

18,077

 

 

 

14,600

 

 

Diluted

 

 

19,156

 

 

 

14,842

 

 

 

19,122

 

 

 

14,732

 

 

 

See accompanying notes to consolidated financial statements.

4




CROSSTEX ENERGY, L.P.
Consolidated Statements of Changes in Partners’ Equity
Six Months ended June 30, 2004
(In thousands)
(Unaudited)

 

 

Common
units

 

Subordinated
units

 

General
partner
interest

 

Accumulated
other
comprehensive
income

 

Total

 

Balance, December 31, 2003 (Restated)

 

$

116,780

 

 

$

33,593

 

 

$

2,854

 

 

$

1,383

 

 

$

154,610

 

Stock based compensation

 

197

 

 

210

 

 

71

 

 

 

 

478

 

Distributions

 

(6,779

)

 

(7,234

)

 

(1,787

)

 

 

 

(15,800

)

Net income

 

4,451

 

 

4,754

 

 

2,442

 

 

 

 

11,647

 

Proceeds from exercise of unit options

 

308

 

 

 

 

 

 

 

 

308

 

Hedging gains or losses reclassified to earnings

 

 

 

 

 

 

 

(1,395

)

 

(1,395

)

Adjustment in fair value of derivatives

 

 

 

 

 

 

 

4,167

 

 

4,167

 

Balance, June 30, 2004

 

$

114,957

 

 

$

31,323

 

 

$

3,580

 

 

$

4,155

 

 

$

154,015

 

 

See accompanying notes to consolidated financial statements.

5




CROSSTEX ENERGY, L.P.
Consolidated Statements of Comprehensive Income
(In thousands)
(Unaudited)

 

 

Six months ended June 30,

 

 

 

      2004      

 

      2003      

 

Net income

 

 

$

11,647

 

 

 

$

5,807

 

 

Hedging gains or losses reclassified to earnings

 

 

(1,395

)

 

 

952

 

 

Adjustment in fair value of derivatives

 

 

4,167

 

 

 

(1,953

)

 

Comprehensive income

 

 

$

14,419

 

 

 

$

4,806

 

 

 

See accompanying notes to consolidated financial statements.

6




CROSSTEX ENERGY, L.P.
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)

 

 

Six months ended June 30,

 

 

 

         2004         

 

         2003         

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

Net income

 

 

$

11,647

 

 

 

$

5,807

 

 

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

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

10,339

 

 

 

5,046

 

 

Loss on investment in affiliated partnerships

 

 

(200

)

 

 

(121

)

 

Non-cash stock based compensation

 

 

478

 

 

 

3,072

 

 

Loss on sale of property

 

 

274

 

 

 

 

 

Minority interest in subsidiary

 

 

99

 

 

 

 

 

Changes in current assets and liabilities, net of acquisition effects:

 

 

 

 

 

 

 

 

 

Accounts receivable and accrued revenue

 

 

(35,533

)

 

 

(36,917

)

 

Prepaid expenses

 

 

(2,533

)

 

 

(1,300

)

 

Accounts payable, accrued gas purchases, and other accrued liabilities 

 

 

39,758

 

 

 

58,896

 

 

Fair value of derivatives

 

 

179

 

 

 

(131

)

 

Other

 

 

424

 

 

 

(1,426

)

 

Net cash provided by operating activities

 

 

24,932

 

 

 

32,926

 

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

Additions to property and equipment

 

 

(15,284

)

 

 

(17,267

)

 

Asset purchases and acquisitions

 

 

(73,013

)

 

 

(67,325

)

 

Proceeds from sale of property

 

 

226

 

 

 

 

 

Additions to other non-current assets

 

 

(145

)

 

 

(872

)

 

Investments in affiliated partnerships

 

 

(48

)

 

 

(646

)

 

Net cash used in investing activities

 

 

(88,264

)

 

 

(86,110

)

 

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

Proceeds from borrowings

 

 

276,000

 

 

 

236,600

 

 

Payments on borrowings

 

 

(212,050

)

 

 

(160,400

)

 

Debt issuance costs

 

 

(1,091

)

 

 

 

 

Increase (decrease) in drafts payable

 

 

16,537

 

 

 

(17,785

)

 

Distribution to partners

 

 

(15,800

)

 

 

(4,291

)

 

Proceeds from exercise of unit options

 

 

308

 

 

 

 

 

Offering costs

 

 

 

 

 

(622

)

 

Net cash provided by financing activities

 

 

63,904

 

 

 

53,502

 

 

Net increase in cash and cash equivalents

 

 

572

 

 

 

318

 

 

Cash and cash equivalents, beginning of period

 

 

166

 

 

 

1,308

 

 

Cash and cash equivalents, end of period

 

 

$

738

 

 

 

$

1,626

 

 

Cash paid for interest

 

 

$

2,778

 

 

 

$

753

 

 

Non-cash transactions, stock-based compensation

 

 

$

478

 

 

 

$

3,072

 

 

 

See accompanying notes to consolidated financial statements.

7




CROSSTEX ENERGY, L.P.
Notes to Consolidated Financial Statements
June 30, 2004
(Unaudited)

(1)   General

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

Crosstex Energy, L.P. (the Partnership), a Delaware limited partnership formed on July 12, 2002, is engaged in the gathering, transmission, treating, processing and marketing of natural gas. The Partnership connects the wells of natural gas producers to its gathering systems in the geographic areas of its gathering systems in order to purchase the gas production, treats natural gas to remove impurities to ensure that it meets pipeline quality specifications, processes natural gas for the removal of natural gas liquids or NGLs, transports natural gas and ultimately provides an aggregated supply of natural gas to a variety of markets. In addition, the Partnership purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee.

The accompanying 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. These consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our restated annual report on Form 10-K/A for the year ended December 31, 2003.

(a)   Income Taxes

The new entities the Partnership formed to acquire LIG Pipeline Company and its subsidiaries, as discussed more fully in Note 3, are treated as taxable corporations for income tax purposes.

For the three and six months ended June 30, 2004, the Partnership recognized a current tax expense of $129,000 on the LIG entities net taxable income. A deferred tax liability of $13,224,000 was recorded at the acquisition date. The deferred tax liability represents future taxes payable on the difference between the purchase price and tax basis of the net assets acquired based on our preliminary purchase price allocation.

(b)   Long-Term Incentive Plans

The Partnership applies the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25), and the related interpretations in accounting for the long-term incentive plans. In accordance with APB No. 25 for fixed stock and unit options, compensation is recorded to the extent the fair value of the stock or unit exceeds the exercise price of the option at the measurement date. Compensation costs for fixed awards with pro rata vesting are recognized on a straight-line basis over the vesting period. In addition, compensation expense is recorded for variable options based on the difference between fair value of the stock or unit and exercise price of the options at period end.

8




Had compensation cost for the Partnership been determined based on the fair value at the grant date for awards in accordance with SFAS No. 123, Accounting for Stock Based Compensation, the Partnership’s net income would have been as follows (in thousands, except per unit amounts):

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

       2004       

 

       2003       

 

      2004      

 

      2003      

 

Net income, as reported

 

 

$

5,941

 

 

 

$

4,975

 

 

 

$

11,647

 

 

 

$

5,807

 

 

Add: Stock-based employee compensation expense included in reported net income

 

 

269

 

 

 

568

 

 

 

478

 

 

 

3,072

 

 

Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards

 

 

(317

)

 

 

(681

)

 

 

(580

)

 

 

(3,289

)

 

Pro forma net income

 

 

$

5,893

 

 

 

$

4,862

 

 

 

$

11,545

 

 

 

$

5,590

 

 

Net income per limited partner unit, as reported:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

$

0.25

 

 

 

$

0.33

 

 

 

$

0.51

 

 

 

$

0.39

 

 

Diluted

 

 

$

0.24

 

 

 

$

0.32

 

 

 

$

0.48

 

 

 

$

0.38

 

 

Pro forma net income per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

$

0.25

 

 

 

$

0.32

 

 

 

$

0.50

 

 

 

$

0.37

 

 

Diluted

 

 

$

0.23

 

 

 

$

0.32

 

 

 

$

0.48

 

 

 

$

0.37

 

 

 

The fair value of each option is estimated on the date of grant using the Black Scholes option-pricing model with the following weighted average assumptions used for Partnership unit grants in the six months ended June 30, 2004:

 

 

2004

 

Options Granted

 

356,779

 

Weighted average dividend yield

 

6.5

%

Weighted average expected volatility

 

24

%

Weighted average risk free interest rate

 

3.09

%

Weighted average expected life

 

5

 

Contractual life

 

10

 

Weighted average of fair value of unit options granted

 

$

3.09

 

 

No Crosstex Energy, Inc. (CEI) options were granted to officers or employees in 2004. Stock based compensation associated with the CEI option plan with respect to officers and employees is recorded by the Partnership since CEI has no operating activities, other than its interest in the Partnership.

CEI modified certain outstanding options attributable to its shares of common stock in the first quarter of 2003, which allowed the option holders to elect to be paid in cash for the modified options based on the fair value of the options. The total number of CEI options which were modified was approximately 364,000. These modified options have been accounted for using variable accounting as of the option modification date. The Partnership accounted for the modified options as variable options until the holders elected to cash out the options or the election to cash out the options lapsed. CEI was responsible for paying the intrinsic value of the options for the holders who elected to cash out their options. December 31, 2003 was the last valuation date that a holder of modified options could elect the cash-out alternative. Accordingly, effective January 1, 2004, the remaining modified options are accounted for as fixed options. Beginning in the first quarter of 2003, the Partnership recognized stock compensation expense based on the estimated fair value at period end of the options modified. The Partnership

9




recognized stock-based compensation expense of approximately $3.1 million related to the variable options for the six months ended June 30, 2003.

In February 2004, 75,000 restricted shares in CEI were issued to senior management under its long-term incentive plan with an intrinsic value of $2,183,000. In February 2004, 1,406 restricted units with an intrinsic value of $29,000 were issued to a director, at his election, for his 2004 annual director fee. These restricted units vest over a five-year period and the intrinsic value of the units is amortized into stock based compensation expense over the vesting period.

(c)   Earnings per Unit and Anti-Dilutive Computations

Basic earnings per unit was computed by dividing net income by the weighted average number of limited partner units outstanding for the three and six months ended June 30, 2004 and 2003. The computation of diluted earnings per unit further assumes the dilutive effect of unit options.

Effective March 29, 2004, the Partnership completed a two-for-one split on its outstanding limited partnership units. All unit amounts for prior periods presented herein have been restated to reflect this unit split.

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three and six months ended June 30, 2004 and 2003 (in thousands):

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

       2004       

 

       2003       

 

      2004      

 

      2003      

 

Basic earnings per unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding

 

 

18,081

 

 

 

14,600

 

 

 

18,077

 

 

 

14,600

 

 

Diluted earnings per unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average limited partner units outstanding

 

 

18,081

 

 

 

14,600

 

 

 

18,077

 

 

 

14,600

 

 

Dilutive effect of exercise of options outstanding

 

 

1,075

 

 

 

242

 

 

 

1,045

 

 

 

132

 

 

Diluted units

 

 

19,156

 

 

 

14,842

 

 

 

19,122

 

 

 

14,732

 

 

 

All outstanding units were included in the computation of diluted earnings per unit.

(d)   New Accounting Pronouncement

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. In December 2003, the FASB issued FIN No. 46R which clarified certain issues identified in FIN 46. FIN No. 46R requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this Interpretation must be applied at the beginning of the first interim or annual period ending after March 15, 2004. In January 2004, the Partnership adopted FIN No. 46R and began consolidating its joint venture interest in the Crosstex DC Gathering, J.V. (CDC), previously accounted for using the equity method of accounting.  The consolidated carrying amount for the joint venture is based on the historical costs of the assets, liabilities and non-controlling interests of the joint venture since its formation in January 2003 which approximates the carrying amount of the assets,

10




liabilities and non-controlling interests in the consolidated financial statements as if FIN No. 46R had been effective upon inception of the joint venture.

(2)   Restatement of Previously Issued Financial Statements

In July 2004, we determined that clerical errors had occurred in 2002 accounting that resulted in certain reconciling items not being properly cleared from accounts payable, accounts receivable and accrued gas purchases with an offsetting decrease in income of $1.7 million in 2002. As a result of correcting these errors, we have restated our consolidated balance sheet and consolidated statements of changes in partners’ equity for the year ended December 31, 2003.

(3)   Significant Asset Purchases and Acquisitions

In April 2004, the Partnership acquired, through its wholly-owned subsidiary Crosstex Louisiana Energy, L.P., the LIG Pipeline Company and its subsidiaries (LIG Inc., Louisiana Intrastate Gas Company, L.L.C., LIG Chemical Company, LIG Liquids Company, L.L.C. and Tuscaloosa Pipeline Company) (collectively, “LIG”) from American Electric Power (“AEP”) in a negotiated transaction for $73.0 million. LIG consists of approximately 2,000 miles of gas gathering and transmission systems located in 32 parishes extending from northwest and north-central Louisiana through the center of the state to south and southeast Louisiana. The Partnership financed the acquisition in April through borrowings under its amended bank credit facility.

We have utilized the purchase method of accounting for this acquisition with an acquisition date of April 1, 2004. The purchase price and our preliminary allocation thereof are as follows (in thousands):

Cash paid to AEP

 

$

69,898

 

Lease obligations bought out

 

671

 

Transaction costs

 

2,444

 

Total Purchase Price

 

$

73,013

 

Assets acquired:

 

 

 

Current assets

 

$

45,172

 

Property plant & equipment

 

92,027

 

Intangibles

 

1,000

 

Liabilities assumed:

 

 

 

Current liabilities

 

(51,962

)

Deferred tax liability

 

(13,224

)

Total Purchase Price

 

$

73,013

 

 

The purchase price allocation for the LIG acquisition has not been finalized because the post closing settlement has not been completed and the Partnership’s valuation consultant has not issued its report related to the purchase price allocation.

On June 30, 2003, the Partnership completed the acquisition of certain assets from Duke Energy Field Services, L.P. (DEFS) for $68.1 million, including the effect of certain purchase price adjustments. The assets acquired included:  the Mississippi pipeline system, a 12.4% interest in the Seminole gas processing plant, the Conroe gas plant and gathering system and the Alabama pipeline system. The Partnership has accounted for this acquisition as a business combination in accordance with SFAS No. 141, Business Combinations. We have utilized the purchase method of accounting for this acquisition with an acquisition date of June 30, 2003.

Operating results for the DEFS assets have been included in the Statements of Operations since June 30, 2003 and operating results for the LIG assets have been included in the Statements of Operations

11




since April 1, 2004. The following unaudited pro forma results of operations assumes that the DEFS acquisition and the LIG acquisition occurred on January 1, 2003 (in thousands, except per unit amounts):

 

 

Pro Forma (unaudited)

 

 

 

Three months
ended June 30,

 

Six months ended June 30,

 

 

 

2003

 

      2004      

 

      2003      

 

Revenue

 

 

$

478,636

 

 

$

1,075,248

 

$

987,166

 

Net income

 

 

3,460

 

 

10,287

 

1,718

 

Net income per limited partner unit

 

 

$

0.23

 

 

$

0.44

 

$

0.11

 

 

(4)   Investment in Limited Partnerships and Note Receivable

The Partnership owns a 7.86% weighted average interest as the general partner in the five gathering systems of Crosstex Pipeline Partners, L.P. (CPP), a 20.31% interest as a limited partner in CPP, 50% interest in the J.O.B. J.V. and a 50% interest in CDC. In January 2004, the Partnership began consolidating its investment in CDC pursuant to FIN No. 46R. The Partnership accounts for its investments in J.O.B. J.V. and CPP under the equity method, as it exercises significant influence in operating decisions as a general partner in CPP and as a 50% owner in the joint venture. Under this method, the Partnership carries its investments at cost and records its equity in net earnings of the affiliated partnerships as income in other income (expense) in the consolidated statement of operations, and distributions received from them are recorded as a reduction in the Partnership’s investment in the affiliated partnership.

In connection with the formation of CDC, the Partnership agreed to loan the CDC partner up to $1.5 million for its initial capital contribution. The loan bears interest at an annual rate of prime plus 2%. CDC makes payments directly to the Partnership attributable to CDC partner’s 50% share of distributable cash flow to repay the loan. Any balance remaining on the note is due in August 2007. The current portion of loan receivable of $677,000 from the CDC partner is included in current notes receivable as of June 30, 2004. The remaining balance of $932,000 is included in other non-current assets as of June 30, 2004.

(5)   Long-Term Debt

As of June 30, 2004 and December 31, 2003, long-term debt consisted of the following (in thousands):

 

 

June 30,
2004

 

December 31,
2003

 

Acquisition credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2004 and December 31, 2003 were 4.25% and 2.92%, respectively

 

$

9,000

 

 

$

20,000

 

 

Senior secured notes, weighted average interest rate of 6.95% and 6.93%, respectively

 

115,000

 

 

40,000

 

 

Note payable to Florida Gas Transmission Company

 

700

 

 

750

 

 

 

 

124,700

 

 

60,750

 

 

Less current portion

 

(50

)

 

(50

)

 

Debt classified as long-term

 

$

124,650

 

 

$

60,700

 

 

 

In conjunction with the April 2004 acquisition of the LIG Pipeline Company and its subsidiaries discussed in Note (3), the Partnership amended its bank credit facility to increase the borrowing base under its senior secured revolving acquisition facility from $70 million to $100 million and to increase the borrowing base under its senior secured revolving credit working capital and letter of credit facility from $50 million to $100 million. Additionally, the current ratio covenant was eliminated under this amendment.

12




In June 2004, the bank credit facility was further amended allowing for an increase in senior secured notes to $125 million and eliminating the minimum tangible net worth covenant.

In June 2004, the Partnership completed a private placement offering of $75 million in senior secured notes with Prudential Capital Group. The notes mature in 10 years, with an average life of eight years, have an annual coupon of 6.96% and are callable after three years at 103.5% of par. The notes were used to repay borrowings under the Partnership’s revolving credit facility.

As part of the $75 million private placement, the Master Shelf Agreement governing the notes was amended, the following being the significant amendments:

·       increased the aggregate amount of notes that may be issued under the agreement to $125 million;

·       extended the issuance period from June 2006 to June 2007;

·       established a release of collateral provision should the Partnership obtain a senior unsecured debt rating of investment grade by certain rating agencies; and

·       provided a call premium on the $75 million placement beginning June 2007 through June 2013 at rates declining from 3.50% to 0%. The notes are not callable prior to June 2007.

In October 2002, the Partnership entered into an interest rate swap covering a principal amount of $20 million for a period of two years. The Partnership is subject to interest rate risk on its acquisition credit facility. The interest rate swap reduces this risk by fixing the LIBOR rate, prior to credit margin, at 2.29%, on $20 million of related debt outstanding over the term of the swap agreement which expires on November 1, 2004. The Partnership has accounted for this swap as a cash flow hedge of the variable interest payments related to the $20 million of the acquisition credit facility outstanding. Accordingly, unrealized gains or losses relating to the swap which are recorded in other comprehensive income will be reclassified from other comprehensive income to interest expense over the period hedged.  The fair value of the interest rate swap at June 30, 2004 was a $92,000 liability and is included in fair value of derivative liabilities.

(6)   Partners’ Capital

Cash Distributions

In accordance with the partnership agreement, 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 commencing with the quarter ending on March 31, 2003. Distributions will generally be made 98% to the common and subordinated unitholders and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts we distribute in excess of $0.25 per unit, 23% of the amounts we distribute in excess of $0.3125 per unit and 48% of amounts we distribute in excess of $0.375 per unit. Incentive distributions totaling $1,301,000 and $2,254,000 were earned by our general partner for the three months and six  months ended June 30, 2004. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.25 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter.

The Partnership has declared a second quarter 2004 distribution of $0.42 per unit to be paid on August 19, 2004.

13




(7)   Derivatives

The Partnership manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge prices and location risk 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 fair value of derivative assets and liabilities, excluding the interest rate swap, are as follows (in thousands):

 

 

June 30,
2004

 

December 31,
2003

 

Fair value of derivative assets—current

 

$

7,569

 

 

$

4,080

 

 

Fair value of derivative assets—long term

 

10

 

 

 

 

Fair value of derivative liabilities—current

 

(3,277

)

 

(2,278

)

 

Fair value of derivative liabilities—long term

 

(25

)

 

 

 

Net fair value of derivatives

 

$

4,277

 

 

$

1,802

 

 

 

14




Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2004 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than December 2005, with no single contract longer than six months. The Partnership’s counterparties to hedging contracts include Sempra Energy Trading Corp., Morgan Stanley Capital Group, BP Corporation, Duke Energy Trading and Marketing, and AEP Energy Services. Changes in the fair value of the Partnership’s derivatives related to Producer Services gas marketing activities are recorded in earnings. 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.

June 30, 2004

 

Transaction type

 

 

 

Total
volume

 

Pricing terms

 

Remaining term
of contracts

 

Fair value 

 

 

 

 

 

 

 

 

 

(in thousands)

 

Cash Flow Hedge:

 

 

 

 

 

 

 

 

 

 

 

Natural gas swaps cash flow hedge

 

5,590,000

 

Fixed prices ranging from
$4.795 to $6.525 settling

 

July 2004—December 2005

 

 

$

6,280

 

 

Natural gas swaps cash flow hedge

 

(2,817,000

)

against various Inside FERC
Index prices

 

July 2004—December 2005

 

 

(1,481

)

 

Total natural gas swaps cash flow hedge

 

 

$

4,799

 

 

Swing swaps cash flow hedge(a)

 

3,100,000

 

Fixed prices ranging from
$5.965 to $6.275 settling

 

July 2004—August 2004

 

 

$

(82

)

 

Swing swaps cash flow
hedge

 

(1,362,264

)

against various Inside FERC
Index prices

 

July 2004—August 2004

 

 

(121

)

 

Total Swing swap cash flow hedge

 

 

$

(203

)

 

Natural gas
liquids (“NGLS”)
swaps cash flow
hedge

 

(3,683,000

)

Fixed prices ranging from
$.3775 to $.7450 settling
against Mt. Belvieu Average
of daily postings (non-TET)

 

July 2004—December 2004

 

 

$

(350

)

 

Total NGL swaps cash flow hedge

 

 

$

(350

)

 

Producer Services:

 

 

 

 

 

 

 

 

 

 

 

Marketing trading financial swaps

 

480,000

 

Fixed prices ranging from
$4.64 to $5.945 settling

 

July 2004—March 2005

 

 

$

641

 

 

Marketing trading financial swaps

 

(450,000

)

against various Inside FERC
Index prices

 

July 2004—March 2005

 

 

(307

)

 

Total marketing trading financial swaps

 

 

$

334

 

 

Physical offset to marketing trading transactions

 

450,000

 

Fixed prices ranging from
$4.64 to $5.855 settling

 

July 2004—March 2005

 

 

$

333

 

 

Physical offset to marketing trading transactions

 

(480,000

)

against various Inside
FERC Index prices

 

July 2004—March 2005

 

 

(636

)

 

Total physical offset to marketing trading transactions swaps

 

 

$

(303

)

 


(a)           Swing swaps are used to hedge the price exposure the Partnership has when it buys or sells a volume of gas at a first of the month index price and the other side of the transaction is priced at a daily gas price during the month. The swing swap functions to hedge against this exposure by buying or selling a swap at a daily price offsetting a first of the month index price or fixed price, where the Partnership’s daily price is the opposite of what it is physically buying or selling at a daily price.

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.

Assets and liabilities related to Producer Services that are accounted for as derivative contracts held for trading purposes are included in the fair value of derivative assets and liabilities and Producer Services

15




operating results are recorded net as profit (loss) on energy trading activities in the consolidated statement of operations. The Partnership estimates the fair value of all of its energy trading contracts using prices actively quoted. 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

 

Two to three years

 

Total fair value

 

June 30, 2004

 

 

$

31

 

 

 

 

 

 

 

 

 

$

31

 

 

December 31, 2003

 

 

$

(26

)

 

 

 

 

 

 

 

 

$

(26

)

 

 

(8)   Transactions with Related Parties

General and Administrative Expense Cap

The Partnership had a $6.0 million annual ($1.5 million quarterly) general and administrative cap for the twelve-month period ended in December 2003, per its partnership agreement. CEI bore the cost of any excess general and administrative expenses. During the three and six months ended June 30, 2004, the Partnership had excess expenses of approximately $0.7 and $1.0 million, respectively. The general partner is also reimbursed for direct charges it incurs on behalf of partnership business development activities. Such charges totaled $0.4 million for the three and six months ended June 30, 2003 and are included in general and administrative expenses.

Camden Resources, Inc.

The Partnership treats gas for, and purchases gas from, Camden Resources, Inc. (Camden). Camden is an affiliate of the Partnership by way of equity investments made in Camden by Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P., collectively the major shareholder in CEI. During the three months ended June 30, 2004 and 2003, the Partnership purchased natural gas from Camden in the amount of approximately $10 million and $2.9 million, respectively, and received approximately $13,000 and $76,000 in treating fees from Camden. The Partnership purchased natural gas from Camden in the amount of approximately $18.2 million and $5.5 million for the six months ended June 30, 2004 and 2003, respectively, and received approximately $31,000 and $138,000, respectively, in treating fees from Camden.

Crosstex Pipeline Partners, L.P.

The Partnership had related-party transactions with Crosstex Pipeline Partners, L.P. (CPP), as summarized below:

·                    During the three months ended June 30, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $2.7 million and $2.6 million and paid for transportation of approximately $10,400 and $9,700, respectively, to CPP. During the six months ended June 30, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $4.9 million and $3.8 million and paid for transportation of approximately $22,000 and $23,000, respectively, to CPP.

·                    During the three months ended June 30, 2004 and 2003, the Partnership received a management fee from CPP of $31,000 in each period. During the six months ended June 30, 2004 and 2003, the Partnership received a management fee from CPP of $63,000 in each period.

·                    During the three months ended June 30, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $30,000 and $20,000, respectively. During the six months ended June 30, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $51,000 and $58,000, respectively.

16




(9)   Commitments and Contingencies

(a)   Employment Agreements

Each member of senior management of the Partnership is a party to an employment contract with the general partner. The employment agreements provide each member of senior management with severance payments in certain circumstances and prohibit each such person from competing with the general partner or its affiliates for a certain period of time following the termination of such person’s employment.

(b)   Environmental Issues

The Partnership acquired two assets from DEFS in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas and a compressor station near Cadeville, Louisiana. At both of these sites, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million, and the remediation cost for the Cadeville site is currently estimated to be approximately $1.2 million. Under the purchase agreement, DEFS has retained liability for cleanup of both the Conroe and Cadeville sites. Moreover, DEFS has entered into an agreement with a third-party company pursuant to which the remediation costs associated with the Conroe site have been assumed by this third-party company that specializes in remediation work. Therefore, the Partnership does not expect to incur any material environmental liability associated with the Conroe or Cadeville sites.

The Partnership acquired LIG Pipeline Company and its subsidiaries on April 1, 2004. Contamination from certain acquired sites from historical operations has been identified that exceed the applicable state corrective action levels. The seller of the company retained liability for the remediation of these sites and has entered into an agreement with a third party pursuant to which the remediation associated with these sites will be covered. In addition, the remediation by the third party is backed by an environmental insurance policy. As a result, the Partnership does not expect to incur any material environmental liability associated with these sites.

Additionally, possible issues have been discovered with respect to Clean Air Act monitoring deficiencies. The Partnership has disclosed these deficiencies to the Louisiana Department of Environmental Quality and is working with the department to correct permit conditions and 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 Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.

The Partnership receives notices from pipeline companies from time to time of gas volume allocation corrections related to gas deliveries on their pipeline systems. These allocation corrections normally have little impact on the Partnership’s gross margin because the Partnership balances its purchases and sales in the pipelines and both the purchase and sale on the pipeline system require corrections. As of June 30, 2004 and December 31, 2003, a subsidiary of the Partnership was involved in a dispute related to one such allocation correction with a pipeline company and a customer on that pipeline. As of December 31, 2003, the Partnership had recorded a receivable of $1.2 million in other current receivables and a liability of $1.2 million in other current liabilities related to this allocation correction. The Partnership resolved this

17




dispute during the second quarter of 2004 at no loss to the Partnership and the related receivables and payables will be collected and paid by the end of the third quarter.

(10)   Segment Information

Identification of operating segments is based principally upon differences in the types and distribution channel of products. The Partnership’s reportable segments consist of Midstream and Treating. The Midstream division consists of the Partnership’s natural gas gathering and transmission operations and includes the Mississippi System, the Conroe System, the Gulf Coast System, the Corpus Christi System, the Gregory Gathering System located around the Corpus Christi area, the Arkoma system in Oklahoma, the Vanderbilt System located in south Texas, the LIG pipelines and processing plants located in Louisiana and various other small systems. Also included in the Midstream division are the Partnership’s Producer Services operations. The operations in the Midstream segment are similar in the nature of the products and services, the nature of the production processes, the type of customer, the methods used for distribution of products and services and the nature of the regulatory environment. The Treating division generates fees from its plants either through volume-based treating contracts or though fixed monthly payments. Included in the Treating division are four gathering systems that are connected to the treating plants and the Seminole plant located in Gaines County, Texas.

The Partnership evaluates the performance of its operating segments based on earnings before income taxes and accounting changes, and after an allocation of corporate expenses. Corporate expenses are allocated to the segments on a pro rata basis based on assets. Inter-segment sales are at cost.

18




Summarized financial information concerning the Partnership’s reportable segments is shown in the following table. The information includes all significant non-cash items.

 

 

Midstream

 

Treating

 

Totals

 

 

 

(in thousands)

 

Three months ended June 30, 2004:

 

 

 

 

 

 

 

Sales to external customers

 

$

507,744

 

$

7,568

 

$

515,312

 

Inter-segment sales

 

1,415

 

(1,415

)

 

Interest expense, net

 

(2,153

)

(33

)

(2,186

)

Stock-based compensation expense

 

225

 

44

 

269

 

Depreciation and amortization

 

4,704

 

1,217

 

5,921

 

Segment profit

 

4,356

 

1,585

 

5,941

 

Segment assets

 

477,514

 

76,787

 

554,301

 

Capital expenditures

 

2,394

 

5,327

 

7,721

 

Three months ended June 30, 2003:

 

 

 

 

 

 

 

Sales to external customers

 

$

224,030

 

$

5,222

 

$

229,252

 

Inter-segment sales

 

2,405

 

(2,405

)

 

Interest expense, net

 

454

 

11

 

465

 

Stock-based compensation expense

 

454

 

114

 

568

 

Depreciation and amortization

 

1,895

 

716

 

2,611

 

Segment profit

 

4,100

 

875

 

4,975

 

Segment assets

 

340,814

 

11,751

 

352,565

 

Capital expenditures

 

10,583

 

2,441

 

13,024

 

Six months ended June 30, 2004:

 

 

 

 

 

 

 

Sales to external customers

 

$

825,957

 

$

14,712

 

$

840,669

 

Inter-segment sales

 

2,838

 

(2,838

)

 

Interest expense, net

 

(3,283

)

(58

)

(3,341

)

Stock-based compensation expense

 

400

 

78

 

478

 

Depreciation and amortization

 

8,264

 

2,075

 

10,339

 

Segment profit

 

8,076

 

3,571

 

11,647

 

Segment assets

 

477,514

 

76,787

 

554,301

 

Capital expenditures

 

6,741

 

9,031

 

15,772

 

Six months ended June 30, 2003:

 

 

 

 

 

 

 

Sales to external customers

 

$

469,345

 

$

10,477

 

$

479,822

 

Inter-segment sales

 

3,909

 

(3,909

)

 

Interest expense, net

 

856

 

19

 

875

 

Stock-based compensation expense

 

2,458

 

614

 

3,072

 

Depreciation and amortization

 

3,715

 

1,331

 

5,046

 

Segment profit

 

4,430

 

1,377

 

5,807

 

Segment assets

 

340,814

 

11,751

 

352,565

 

Capital expenditures

 

12,903

 

4,364

 

17,267

 

 

19




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

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

Overview

We are a Delaware limited partnership formed by Crosstex Energy, Inc. on July 12, 2002 to acquire indirectly substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast and in Mississippi and Louisiana. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while our Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. For the six months ended June 30, 2004, 76% of our gross margin was generated in the Midstream division, with the balance in the Treating division. We focus on gross margin to manage our business because our business is generally to gather, process, transport, market or treat gas for a fee or a buy-sell margin.

Our results of operations are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facilities or treated at our treating plants as well as fees earned from recovering carbon dioxide and natural gas liquids at a non-operated processing plant. We generate revenues from five primary sources:

·       gathering, transporting and reselling natural gas on the pipeline systems we own;

·       processing natural gas at our processing plants;

·       treating natural gas at our treating plants;

·       recovering carbon dioxide and natural gas liquids at a non-operated processing plant; and

·       providing producer services.

The bulk of our operating profits are derived from the margins we realize for gathering and transporting natural gas through our pipeline systems. Generally, we buy gas from a producer, plant tailgate, or transporter at either a fixed discount to a market index or a percentage of the market index. We then transport and resell the gas. The resale price is based on the same index price at which the gas was purchased, and, if we are to be profitable, at a smaller discount or larger premium to the index than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” below for a discussion of how we manage our business to reduce the impact of price volatility.

We generate producer services revenues through the purchase and resale of natural gas. We focus on supply aggregation transactions in which we either purchase and resell gas and thereby eliminate the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer.

We generate treating revenues under three arrangements:

·       a volumetric fee based on the amount of gas treated, which accounted for approximately 55% and 63% of the operating income in our Treating division for the six months ended June 30, 2004 and 2003, respectively;

20




·       a fixed fee for operating the plant for a certain period, which accounted for approximately 40% and 30% of the operating income in our Treating division for the six months ended June 30, 2004 and 2003, respectively; or

·       a fee arrangement in which the producer operates the plant, which accounted for approximately 5% and 7% of the operating income in our Treating division for the six months ended June 30, 2004 and 2003, respectively.

Typically, we incur minimal incremental operating or administrative overhead costs when gathering and transporting additional natural gas through our pipeline assets. Therefore, we recognize a substantial portion of incremental gathering and transportation margins as operating income.

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 and associated transportation and communication costs, property insurance, ad valorem taxes, repair and maintenance expenses, measurement 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 moved through the asset.

Our general and administrative expenses are dictated by the terms of our partnership agreement and our omnibus agreement with Crosstex Energy, Inc. Our general partner and its affiliates are reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. For the 12 month period ended in December 2003, the amount which we reimbursed our general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf could not exceed $6.0 million. This reimbursement cap did not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on our behalf. This cap expired in December 2003.

We have grown significantly through asset purchases in recent years, which creates many of the major differences when comparing operating results from one period to another. We acquired the assets from Duke Energy Field Services (DEFS) in June 2003 for $68.1 million in cash. The principal assets acquired were the Mississippi pipeline system, a 638-mile natural gas gathering and transmission system in south central Mississippi, and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for major oil companies in West Texas.

Our most recent asset purchase was completed in April 2004, when we acquired LIG Pipeline Company and its subsidiaries (collectively, “LIG”) from a subsidiary of American Electric Power (“AEP”) for $73.0 million in cash. The principal assets acquired consist of approximately 2,000 miles of gas gathering and transmission systems located in 32 parishes extending from northwest and north-central Louisiana through the center of the state to the south and southeast Louisiana and five processing plants, three of which are currently idle, that straddle the pipeline in three locations and have a total processing capability of 663,000 MMbtu/d. The system has a throughput capacity of 900,000 MMbtu/d and average throughput at the time of our acquisition was approximately 560,000 MMbtu/d. Customers include power plants, municipal gas systems, and industrial markets located principally in the industrial corridor between New Orleans and Baton Rouge. The LIG system is connected to several interconnected pipelines and the Jefferson Island Storage facility providing access to additional system supply. We financed the LIG acquisition through borrowings under our bank credit facility.

21




Results of Operations

Set forth in the table below is certain financial and operating data for the Midstream and Treating divisions for the periods indicated.

 

 

Three months ended June 30,

 

Six months ended June 30,

 

 

 

2004

 

2003

 

2004

 

2003

 

 

 

(in millions, except volume amounts)

 

Midstream revenues

 

$

507.7

 

$

224.0

 

$

826.0

 

$

469.3

 

Midstream purchased gas

 

485.2

 

214.1

 

788.1

 

451.5

 

Midstream gross margin

 

22.5

 

9.9

 

37.9

 

17.8

 

Treating revenues

 

7.6

 

5.2

 

14.7

 

10.5

 

Treating purchased gas

 

1.5

 

2.0

 

2.9

 

4.5

 

Treating gross margin

 

6.1

 

3.2

 

11.8

 

6.0

 

Total gross margin

 

$

28.6

 

$

13.1

 

$

49.7

 

$

23.8

 

Midstream Volumes (MMBtu/d):

 

 

 

 

 

 

 

 

 

Gathering and transportation

 

1,248,000

 

506,000

 

1,255,000

 

503,000

 

Processing

 

390,000

 

93,000

 

405,000

 

94,000

 

Producer services

 

166,000

 

262,000

 

181,000

 

258,000

 

Treating Volumes (MMBtu/d)

 

79,000

 

89,000

 

81,000

 

89,000

 

 

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003

Gross Margin.   Midstream gross margin was $22.5 million for the three months ended June 30, 2004 compared to $9.9 million for the three months ended June 30, 2003, an increase of $12.6 million, or 127%. The majority of this increase was due to the acquisition of the LIG assets on April 1, 2004, which added $8.1 million to midstream gross margin. In addition, the DEFS assets, which were acquired on June 30, 2003, added $3.4 million. The Arkoma, Gulf Coast, Vanderbilt and CCNG systems had growth in on-system transmission and gathering volumes of 20% resulting in an aggregate increase in gross margin of $0.8 million. The Denton County gathering system, which was under construction during the comparative period in 2003, generated gross margin of $0.3 million in the second quarter of 2004.

Treating gross margin was $6.1 million for the three months ended June 30, 2004 compared to $3.2 million in the same period in 2003, an increase of $2.9 million, or 91%. Of this increase, $2.0 million was due to the Seminole Plant, which was one of the assets acquired from DEFS. In addition, new plants placed in service since June 30, 2003 generated an additional $1.1 million in gross margin. These increases were partially offset by a decrease in gross margin of $0.2 million due to plants that were in service during the second quarter of 2003 but were held in inventory during the second quarter of 2004, and a decrease in margin of $0.3 million at our volume-sensitive treating plants.

Operating Expenses.   Operating expenses were $10.3 million for the three months ended June 30, 2004 compared to $3.3 million for the three months ended June 30, 2003, an increase of $7.0 million, or 209%. An increase of $3.0 million was associated with the acquisition of the LIG assets and an increase of $1.9 million was associated with the acquisition of assets from DEFS. Costs for our technical services and general operations support increased by approximately $0.9 million due to staff additions to operate the LIG assets and the assets acquired from DEFS and to manage other construction projects. The growth in treating plants in service increased operating expenses by $0.3 million.

General and Administrative Expenses.   General and administrative expenses were $4.7 million for the three months ended June 30, 2004 compared to $1.9 million for the three months ended June 30, 2003, an increase of $2.8 million, or 147%. The increase was due in part to the general and administrative expense limit set by our partnership agreement for the year of 2003, which resulted in general and administrative

22




expenses in excess of specified levels being borne by the general partner. Had the cap not been in place, general and administrative expenses would have been $2.6 million, resulting in an actual increase from 2003 to 2004 of $2.1 million. The increase was primarily due to increases in staffing associated with the requirements of the LIG and DEFS acquisitions and growth in the Partnership’s treating business and its other assets as discussed above.

Stock Based Compensation.   Stock based compensation expense decreased from $0.6 million in the second quarter of 2003 to $0.3 million in the second quarter of 2004. During 2003, certain outstanding CEI options were accounted for using variable accounting due to a “cash-out” modification offered for such options and stock compensation expense was recognized because the estimated fair value of the options increased during 2003. The “cash-out” modification offered during 2003 that caused the variable accounting treatment expired on December 31, 2003 and, effective January 1, 2004, the remaining CEI options are accounted for as fixed options. Stock based compensation recognized in 2004 represents the amortization of costs associated with awards under long-term incentive plans, including restricted units and option grants with exercise prices below market prices on the grant date.

Depreciation and Amortization.   Depreciation and amortization expenses were $5.9 million for the three months ended June 30, 2004 compared to $2.6 million for the three months ended June 30, 2003, an increase of $3.3 million, or 127%. The increase related to the DEFS assets was $1.2 million and the increase related to the LIG assets was $1.1 million. New treating plants placed in service resulted in an increase of $0.5 million. The remaining $0.5 million increase in depreciation and amortization is a result of expansion projects and other new assets, including the expansion of the Gregory Plant.

Interest Expense.   Interest expense was $2.2 million for the three months ended June 30, 2004 compared to $0.5 million for the three months ended June 30, 2003, an increase of $1.7 million, or 370%. The increase relates primarily to an increase in debt outstanding and due to higher interest rates between three-month periods (weighted average rate of 5.4% in 2004 compared to 5.2% in 2003).

Net Income.   Net income for the three months ended June 30, 2004 was $5.9 million compared to $5.0 million for the three months ended June 30, 2003, an increase of $0.9 million. This was generally the result of the increase in gross margin of $15.0 million between comparative quarters from 2003 to 2004, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses and interest expense as discussed above. Depreciation and amortization expense also increased.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

Gross Margin.   Midstream gross margin was $37.9 million for the six months ended June 30, 2004 compared to $17.8 million for the six months ended June 30, 2003, an increase of $20.1 million, or 113%. The largest portion of this increase was due to the acquisition of the LIG assets on April 1, 2004, which added $8.1 million to midstream gross margin. In addition, the DEFS assets, which were acquired on June 30, 2003, added $6.8 million. The Arkoma, Gulf Coast, Vanderbilt and CCNG systems had growth in on-system transmission and gathering volumes of 14% resulting in an aggregate increase in gross margin of $4.7 million. The Denton County gathering system , which was under construction during the comparative period in 2003, generated gross margin of $0.6 million in the first six months of 2004.

Treating gross margin was $11.8 million for the six months ended June 30, 2004 compared to $6.0 million in the same period in 2003, an increase of $5.8 million, or 97%. Of this increase, $3.9 million was due to the Seminole Plant, which was one of the assets acquired from DEFS. In addition, new plants placed in service since June 30, 2003 generated an additional $1.8 million in gross margin. These increases were partially offset by a decrease in gross margin of $0.2 million due to plants that were in service during the first half of 2003 but were held in inventory during the first half of 2004, and a decrease in margin of $0.5 million at our volume-sensitive treating plants.

23




Operating Expenses.   Operating expenses were $16.5 million for the six months ended June 30, 2004 compared to $6.5 million for the six months ended June 30, 2003, an increase of $10.0 million, or 153%. An increase of $3.4 million was associated with the acquisition of assets from DEFS and an increase of $3.0 million was associated with the acquisition of the LIG assets. Costs for our technical services and general operations support increased by approximately $1.5 million due to staff additions to operate the LIG assets acquired in April 2004 and the assets acquired in June 2003 from DEFS and to manage other construction projects. The growth in treating plants in service increased operating expenses by $0.5 million.

General and Administrative Expenses.   General and administrative expenses were $8.3 million for the six months ended June 30, 2004 compared to $3.4 million for the six months ended June 30, 2003, an increase of $4.9 million, or 146%. The increase was due in part to the general and administrative expense limit set by our partnership agreement for the year of 2003, which resulted in general and administrative expenses in excess of specified levels being borne by the general partner. Had the cap not been in place, general and administrative expenses would have been $4.6 million, resulting in an actual increase from 2003 to 2004 of $3.7 million. The increase was primarily due to increases in staffing associated with the requirements of the LIG and DEFS acquisitions and growth in the Partnership’s treating business and its other assets as discussed above.

Stock Based Compensation.   Stock based compensation expense decreased from $3.0 million in the second half of 2003 to $0.5 million in the second half of 2004. During 2003, certain outstanding CEI options were accounted for using variable accounting due to a “cash-out” modification offered for such options and stock compensation expense was recognized because the estimated fair value of the options increased during 2003. The “cash-out” modification offered during 2003 that caused the variable accounting treatment expired on December 31, 2003 and, effective January 1, 2004, the remaining CEI options are accounted for as fixed options. Stock based compensation recognized in 2004 represents the amortization of costs associated with awards under long-term incentive plans, including restricted units and option grants with exercise prices below market prices on the grant date.

(Profit) Loss on Energy Trading Activities.   The profit on energy trading activities was $1.2 million for the six months ended June 30, 2004 compared to $0.8 million for the six months ended June 30, 2003, an increase of $0.4 million. Included in these amounts are realized margins on delivered volumes in the producer services “off-system” gas marketing operations of $1.2 million in the first half of 2004 and 2003.

Loss on Sale of Property.   In the first six months of 2004, we sold two small gathering systems and recognized a net loss on sale of $274,000.

Depreciation and Amortization.   Depreciation and amortization expenses were $10.3 million for the six months ended June 30, 2004 compared to $5.0 million for the six months ended June 30, 2003, an increase of $5.3 million, or 105%. The increase related to the DEFS assets was $2.4 million and the increase related to the LIG assets and was $1.1 million. New treating plants placed in service resulted in an increase of $0.8 million. The remaining $0.7 million increase in depreciation and amortization is a result of expansion projects and other new assets, including the expansion of the Gregory Plant.

Interest Expense.   Interest expense was $3.3 million for the six months ended June 30, 2004 compared to $0.9 million for the six months ended June 30, 2003, an increase of $2.4 million, or 282%. The increase relates primarily to an increase in debt outstanding and due to higher interest rates between six-month periods (weighted average rate of 5.5% in 2004 compared to 4.9% in 2003).

Net Income.   Net income for the six months ended June 30, 2004 was $11.6 million compared to $5.8 million for the six months ended June 30, 2003, an increase of $5.8 million. This was generally the result of the increase in gross margin of $25.5 million, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses and interest expense as discussed above. Depreciation and amortization expenses also increased.

24




Critical Accounting Policies

Information regarding the Partnership’s Critical Accounting Policies is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2003.

Liquidity and Capital Resources

Cash Flows.   Net cash provided by operating activities was $24.9 million for the six months ended June 30, 2004 compared to cash provided by operations of $32.9 million for the six months ended June 30, 2003. Income before non-cash income and expenses was $22.6 million in 2004 and $13.8 million in 2003. Changes in working capital provided $2.3 million in cash flows from operating activities in 2004 and $19.1 million in cash flows from operating activities in 2003. Income before non-cash income and expenses increased between periods primarily due to asset acquisitions as discussed in “Results of Operations—Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003.”

Net cash used in investing activities was $88.3 million and $86.1 million for the six months ended June 30, 2004 and 2003, respectively. Net cash used in investing activities during 2004 related to the LIG acquisition, refurbishment and installation of treating plants, the connection of new wells to various systems, pipeline integrity projects, pipeline relocations and various other internal growth projects. During 2003, net cash used in investing activities primarily related to the DEFS acquisition and other costs related to internal growth projects including the Gregory plant expansion and buying, refurbishing and installing treating plants.

Net cash provided by financing activities was $63.9 million for the six months ended June 30, 2004 compared to $53.5 million provided by financing activities for the six months ended June 30, 2003. Net borrowings of $64.0 million in the first half of 2004 were used to fund the LIG acquisition and the internal growth projects discussed above. Distributions to partners totaled $15.8 million in the first half of 2004, compared to distributions in the first half of 2003 of $4.3 million. Drafts payable increased by $16.5 million providing cash for financing activities for the six months ended June 30, 2004 as compared to a decrease in drafts payable of $17.8 million using cash from financing activities for the six months ended June 30, 2003. In order to reduce our interest costs, we do 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 our revolving credit facility.

Off-Balance Sheet Arrangements.   We had no off-balance sheet arrangements as of June 30, 2004.

Indebtedness

As of June 30, 2004 and December 31, 2003, long-term debt consisted of the following (in thousands):

 

 

June 30,
2004

 

December 31,
2003

 

Acquisition credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2004 and December 31, 2003 were 4.25% and 2.92%, respectively

 

$

9,000

 

 

$

20,000

 

 

Senior secured notes, weighted average interest rate of 6.95% and 6.93% at June 30, 2004 and December 31, 2003, respectively

 

115,000

 

 

40,000

 

 

Note payable to Florida Gas Transmission Company

 

700

 

 

750

 

 

 

 

124,700

 

 

60,750

 

 

Less current portion

 

50

 

 

50

 

 

Debt classified as long-term

 

$

124,650

 

 

$

60,700

 

 

 

25




In conjunction with the April 2004 acquisition of the LIG Pipeline Company and its subsidiaries discussed in Note (3) of Notes to Consolidated Financial Statements, the Partnership amended its bank credit facility to increase the borrowing base under its senior secured revolving acquisition facility from $70 million to $100 million and to increase the borrowing base under its senior secured revolving credit working capital and letter of credit facility from $50 million to $100 million. Additionally, the current ratio covenant was eliminated under this amendment. In June 2004, the bank credit facility was further amended allowing for an increase in senior secured notes to $125 million and eliminating the minimum tangible net worth covenant.

In June 2004, the Partnership completed a private placement offering of $75 million in senior secured notes with Prudential Capital Group. The notes mature in 10 years, with an average life of eight years, have an annual coupon of 6.96% and are callable after three years at 103.5% of par. The notes were used to repay borrowings under the Partnership’s revolving credit facility.

As part of the $75 million private placement, the Master Shelf Agreement governing the notes was amended, the following being the significant amendments:

·       increased the aggregate amount of notes that may be issued under the agreement to $125 million;

·       extended the issuance period from June 2006 to June 2007;

·       established a release of collateral provision should the Partnership obtain a senior unsecured debt rating of investment grade by certain rating agencies; and

·       provided a call premium on the $75 million placement beginning June 2007 through June 2013 at rates declining from 3.50% to 0%. The notes are not callable prior to June 2007.

Disclosure Regarding Forward-Looking Statements

This report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 31E of the Securities Exchange Act of 1934, as amended. Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” 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. In addition to specific uncertainties discussed elsewhere in this Form 10-Q, the following risks and uncertainties may affect our performance and results of operations:

·       we may not have sufficient cash after the establishment of cash reserves and payment of our general partner’s fees and expenses to pay the minimum quarterly distribution each quarter;

·       if we are unable to contract for new natural gas supplies, we will be unable to maintain or increase the throughput levels in our natural gas gathering systems and asset utilization rates at our treating and processing plants to offset the natural decline in reserves;

·       our profitability is dependent upon the prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile;

·       our future success will depend in part on our ability to make acquisitions of assets and businesses at attractive prices and to integrate and operate the acquired business profitably;

26




·       Crosstex Energy, Inc. owns approximately 55% aggregate limited partner interest of us and it owns and controls our general partner, thereby effectively controlling all limited partnership decisions; conflicts of interest may arise in the future between Crosstex Energy, Inc. and its affiliates, including our general partner, and our partnership or any of our unitholders;

·       since we are not the operator of certain of our assets, the success of the activities conducted at such assets are outside our control;

·       we operate in very competitive markets and encounter significant competition for natural gas supplies and markets;

·       we are subject to risk of loss resulting from nonpayment or nonperformance by our customers or counterparties;

·       we may not be able to retain existing customers, especially key customers, or acquire new customers at rates sufficient to maintain our current revenues and cash flows;

·       the construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital and subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities;

·       our business involves many hazards and operational risks, some of which may not be fully covered by insurance. Our operations are subject to many hazards inherent in the gathering, compressing, treating and processing of natural gas and storage of residue gas, including damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism; inadvertent damage from construction and farm equipment; leaks from natural gas, NGLs and other hydrocarbons; and fires and explosions. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risks incident to our business. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition;

·       we are subject to extensive and changing federal, state and local laws and regulations designed to protect the environment, and these laws and regulations could impose liability for remediation costs and civil or criminal penalties for non-compliance; and

·       our common units may not have significant trading volume or liquidity, and the price of our common units may be volatile and may decline if interest rates increase.

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. We face market risk from commodity price variations, primarily due to fluctuations in the price of a portion of the natural gas we sell; and for the portion of the natural gas we process and for which we have taken the processing risk, we are at risk for the difference in the value of the natural gas liquid (“NGL”) products we produce versus the value of the gas used in fuel and shrinkage in their production. In addition, a portion of our loss at certain processing operations is denominated in natural gas liquids. We also incur credit risks and risks related to interest rate variations.

27




Commodity Price Risk.   Approximately 8.3% of the natural gas we market is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the gas at a percentage of the index price, our resell margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. We also receive a portion of our fees at certain of our processing operations in the form of a percentage of the liquids produced. Therefore, our margins are also exposed to volatility in the changing price of liquids. In addition, of the gas we process at our Gregory Processing Plant, we were exposed to the processing risk on 3.7% of the gas we purchased during the six months ended June 30, 2004. Our processing margins on this portion of the gas will be higher during periods when the price of gas is low relative to the value of the liquids produced and our margins will be lower during periods when the value of gas is high relative to the value of liquids. For the six months ended June 30, 2004, a $0.01 per gallon change in NGL prices offset by a change of $0.10 per MMBtu in the price of natural gas would have reduced our processing margin by $58,000. Changes in natural gas prices indirectly may impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we can gather, transport, process and treat.

Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a Risk Management Committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas and natural gas liquids using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our Risk Management Committee. Hedges to protect our processing margins are generally for a more limited time frame than is possible for hedges in natural gas, as the financial markets for NGLs are not as developed as the markets for natural gas. Such hedges generally involve taking a short position with regard to the relevant liquids and an offsetting long position in the required volume of natural gas.

The use of financial instruments may expose us 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) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.

We manage our price risk related to future physical purchase or sale commitments for our producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas prices. However, we are subject to counterparty risk for both the physical and financial contracts. We account for certain of our producer services natural gas marketing activities as energy trading contracts or derivatives. These energy-trading contracts are recorded at fair value with changes in fair value reported in earnings. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to our producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.

For each reporting period, we record the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In addition, realized gains and losses from settled contracts are also recorded in profit or loss on energy trading contracts.

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2004 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than December 2005, with no single contract longer than six months. Our counterparties to hedging contracts include Sempra Energy Trading Corp., Morgan

28




Stanley Capital Group, BP Corporation, Duke Energy Trading and Marketing and AEP Energy Services. Changes in the fair value of our derivatives related to Producer Services gas marketing activities are recorded in earnings. 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.

June 30, 2004

 

Transaction type

 

 

 

Total
volume

 

Pricing terms

 

Remaining term
of contracts

 

Fair value 

 

 

 

 

 

 

 

 

 

(in thousands)

 

Cash Flow Hedge:

 

 

 

 

 

 

 

 

 

 

 

Natural gas swaps cash flow hedge

 

5,590,000

 

Fixed prices ranging from
$4.795 to $6.525 settling

 

July 2004—December 2005

 

 

$

6,280

 

 

Natural gas swaps cash flow hedge

 

(2,817,000

)

against various Inside FERC
Index prices

 

July 2004—December 2005

 

 

(1,481

)

 

Total natural gas swaps cash flow hedge

 

 

$

4,799

 

 

Swing swaps cash flow hedge

 

3,100,000

 

Fixed prices ranging from
$5.965 to $6.275 settling

 

July 2004—August 2004

 

 

$

(82

)

 

Swing swaps cash flow
hedge

 

(1,362,264

)

against various Inside FERC
Index prices

 

July 2004—August 2004

 

 

(121

)

 

Total swing swap cash flow hedge

 

 

$

(203

)

 

NGL swaps cash
flow hedge

 

(3,683,000

)

Fixed prices ranging from
$.3775 to $.7450 settling
against Mt. Belvieu Average
of daily postings (non-TET)

 

July 2004—December 2004

 

 

$

(350

)

 

Total NGL swaps cash flow hedge

 

 

$

(350

)

 

Producer Services:

 

 

 

 

 

 

 

 

 

 

 

Marketing trading financial swaps

 

480,000

 

Fixed prices ranging from
$4.64 to $5.945 settling

 

July 2004—March 2005

 

 

$

641

 

 

Marketing trading financial swaps

 

(450,000

)

against various Inside FERC
Index prices

 

July 2004—March 2005

 

 

(307

)

 

Total marketing trading financial swaps

 

 

$

334

 

 

Physical offset to marketing trading transactions

 

450,000

 

Fixed prices ranging from
$4.64 to $5.855 settling

 

July 2004—March 2005

 

 

$

333

 

 

Physical offset to marketing trading transactions

 

(480,000

)

against various Inside
FERC Index prices

 

July 2004—March 2005

 

 

(636

)

 

Total physical offset to marketing trading transactions swaps

 

 

$

(303

)

 

 

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis.

Interest Rate Risk.    We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. At June 30, 2004, we had $9.0 million of indebtedness outstanding under floating rate debt. We have interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, wherein we have swapped floating rates for fixed rates of 2.29% and the applicable margin through November 1, 2004. The impact of a 100 basis point increase in interest rates on our debt outstanding on June 30, 2004 would result in an increase in interest expense and a decrease in income before taxes of approximately $90,000 per year. This amount has been determined by considering the impact of such hypothetical interest rate increase on our non-hedged, floating rate debt outstanding at June 30, 2004.

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Item 4.   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 GP, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

As we have previously disclosed, in July 2004 we determined during the course of internal reviews that, due to clerical errors, certain reconciling items between the detail accounts receivable and accounts payable subledgers and the general ledger relating to 2002 had not been properly cleared. These errors resulted from a deficiency in the procedures to reconcile these subledgers to the general ledger. During the second quarter of 2004, we implemented new procedures for reconciling subledgers to the general ledger and the disposition and resolution of reconciling items on a timely basis. Management believes that these measures will ensure that similar errors do not occur again. Except for the changes discussed above, there have been no changes in our internal controls over financial reporting that occurred during the three months ended June 30, 2004 that have materially affected, or are reasonable likely to materially affect, our internal controls over financial reporting.

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PART II—OTHER INFORMATION

Item 6.   Exhibits and Reports on Form 8-K

(a)           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

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

3.2

Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 29, 2004 (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).

3.3

Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).

3.4

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

3.5

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 our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).

3.6

Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to our Registration Statement on Form S-1, file No. 333-97779).

3.7

Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to our Registration Statement on Form S-1, file No. 333-97779).

3.8

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

3.9

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 our Registration Statement on Form S-1, File No. 333-106927).

4.1

Specimen Unit Certificate for Common Units (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-1, file No. 333-97779).

10.1*

Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of June 18, 2004, by and among Crosstex Energy Services, L.P., Union Bank of California, N.A. and certain other parties.

10.2*

Letter Amendment No. 2 to Master Shelf Agreement, dated as of June 18, 2004, among Crosstex Energy Services, L.P., Prudential Investment Management, Inc., The Prudential Insurance Company of America and Pruco Life Insurance Company.

21.1

List of Subsidiaries (incorporated by reference to Exhibit 21.1 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).

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 principal financial officer of the Company pursuant to 18 U.S.C. Section 1350.


*                    Filed herewith.

31




(b)          Reports on Form 8-K

On April 14, 2004, Crosstex Energy, L.P. filed a Current Report on Form 8-K, (as amended May 21, 2004 and June 11, 2004 to include financial statements of LIG Pipeline Company and subsidiaries) Items 2, 7 and 9, (dated as of April 1, 2004) announcing the acquisition of the LIG Pipeline Company and its subsidiaries from American Electric Power.

On May 5, 2004, Crosstex Energy, L.P. filed a Current Report on Form 8-K, Items 7 and 12 (dated as of May 4, 2004), which included its press release as Exhibit 99.1 announcing its financial results for the three months ended March 31, 2004.

On June 21, 2004, Crosstex Energy, L.P. filed a current report on Form 8-K, Items 7 and 9, (dated as of June 18, 2004) which included its press release as Exhibit 99.1 announcing its completion of a private placement offering of $75 million in senior secured notes.

On June 22, 2004, Crosstex Energy, L.P. filed a current report on Form 8-K, Item 5 (dated as of June 14, 2004) announcing the appointment of Mr. Rhys J. Best to its Board of Directors.

 

32




 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on the 11th day of August 2004.

Crosstex Energy, L.P.

 

By:

Crosstex Energy GP, L.P.,
its general partner

 

 

By:

Crosstex Energy GP, LLC,
its general partner

 

 

 

By:

 /s/ William W. Davis

 

 

 

 

 William W. Davis,

 

 

 

 

 Executive Vice President and Chief Financial Officer

 

33