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Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

 

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

 

for the quarterly period ended June 30, 2012

 

OR

 

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

 

for the transition period from              to              

 

Commission file number: 000-50536

 

CROSSTEX ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

52-2235832

(State of organization)

 

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

 

 

 

2501 CEDAR SPRINGS

 

 

DALLAS, TEXAS

 

75201

(Address of principal executive offices)

 

(Zip Code)

 

(214) 953-9500

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer o

 

Accelerated filer x

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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

 

As of July 27, 2012, the Registrant had 47,388,569 shares of common stock outstanding.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

Item

 

Description

 

Page

 

 

 

 

 

 

 

PART I—FINANCIAL INFORMATION

 

 

 

 

 

 

 

1.

 

Financial Statements

 

3

 

 

 

 

 

2.

 

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

 

21

 

 

 

 

 

3.

 

Quantitative and Qualitative Disclosures About Market Risk

 

34

 

 

 

 

 

4.

 

Controls and Procedures

 

37

 

 

 

 

 

 

 

PART II—OTHER INFORMATION

 

 

 

 

 

 

 

1.

 

Legal Proceedings

 

38

 

 

 

 

 

1A.

 

Risk Factors

 

38

 

 

 

 

 

5.

 

Other Information

 

39

 

 

 

 

 

6.

 

Exhibits

 

41

 



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Condensed Consolidated Balance Sheets

 

 

 

June 30,

 

December 31,

 

 

 

2012

 

2011

 

 

 

(Unaudited)

 

 

 

 

 

(In thousands)

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

8,197

 

$

30,343

 

Restricted cash (1)

 

245,100

 

 

Accounts receivable:

 

 

 

 

 

Trade, net of allowance for bad debt of $362 and $405, respectively

 

37,258

 

22,680

 

Accrued revenue and other

 

103,622

 

143,197

 

Fair value of derivative assets

 

6,680

 

2,867

 

Natural gas and natural gas liquids, prepaid expenses and other

 

22,874

 

9,965

 

Total current assets

 

423,731

 

209,052

 

Property and equipment, net of accumulated depreciation of $446,333 and $406,773, respectively

 

1,286,918

 

1,242,890

 

Fair value of derivative assets

 

1,604

 

 

Intangible assets, net of accumulated amortization of $224,729 and $199,248, respectively

 

425,981

 

451,462

 

Investment in limited liability company

 

87,250

 

35,000

 

Other assets, net

 

22,953

 

24,212

 

Total assets

 

$

2,248,437

 

$

1,962,616

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable, drafts payable, and other

 

$

27,886

 

$

22,549

 

Accrued gas purchases

 

76,787

 

106,233

 

Fair value of derivative liabilities

 

2,839

 

5,587

 

Current portion of long-term debt (1)

 

250,000

 

 

Other current liabilities

 

46,020

 

66,567

 

Accrued interest

 

27,036

 

24,918

 

Total current liabilities

 

430,568

 

225,854

 

Long-term debt

 

762,357

 

798,409

 

Other long-term liabilities

 

22,383

 

23,919

 

Deferred tax liability

 

78,394

 

85,187

 

Fair value of derivative liabilities

 

7

 

 

Commitments and contingencies

 

 

 

Stockholders’ equity

 

954,728

 

829,247

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

2,248,437

 

$

1,962,616

 

 


(1) See Footnote 2 - 2022 Notes for additional information.

 

See accompanying notes to condensed consolidated financial statements.

 

3



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Condensed Consolidated Statements of Operations

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

(Unaudited)

 

 

 

(In thousands, except per share amounts)

 

Revenues

 

$

351,194

 

$

525,735

 

$

722,903

 

$

1,015,505

 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

Purchased gas and NGLs

 

260,890

 

429,177

 

532,846

 

829,111

 

Operating expenses

 

30,571

 

27,913

 

58,378

 

52,957

 

General and administrative

 

13,774

 

13,272

 

29,380

 

25,754

 

Gain on sale of property

 

(406

)

(60

)

(504

)

(80

)

(Gain) loss on derivatives

 

(4,905

)

1,536

 

(2,736

)

4,957

 

Depreciation and amortization

 

32,889

 

31,654

 

65,085

 

61,326

 

Total operating costs and expenses

 

332,813

 

503,492

 

682,449

 

974,025

 

Operating income

 

18,381

 

22,243

 

40,454

 

41,480

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest expense, net of interest income

 

(21,319

)

(20,674

)

(40,699

)

(40,440

)

Other income (expenses)

 

12

 

(242

)

25

 

(130

)

Total other expense

 

(21,307

)

(20,916

)

(40,674

)

(40,570

)

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

 

(2,926

)

1,327

 

(220

)

910

 

Income tax benefit

 

724

 

248

 

788

 

898

 

Net income (loss)

 

(2,202

)

1,575

 

568

 

1,808

 

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

 

(530

)

2,648

 

3,064

 

4,417

 

Net loss attributable to Crosstex Energy, Inc.

 

$

(1,672

)

$

(1,073

)

$

(2,496

)

$

(2,609

)

Net loss per common share:

 

 

 

 

 

 

 

 

 

Basic and diluted common share

 

$

(0.03

)

$

(0.02

)

$

(0.05

)

$

(0.05

)

Weighted average shares outstanding:

 

 

 

 

 

 

 

 

 

Basic and diluted

 

47,366

 

47,140

 

47,361

 

47,108

 

 

See accompanying notes to condensed consolidated financial statements.

 

4



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Comprehensive Income

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Net income (loss)

 

$

(2,202

)

$

1,575

 

$

568

 

$

1,808

 

Hedging losses reclassified to earnings, net of taxes of $7, $70, $41 and $108, respectively

 

65

 

631

 

384

 

980

 

Adjustment in fair value of derivatives, net of taxes of $172, ($14), $175 and ($152), respectively

 

1,618

 

(126

)

1,582

 

(1,384

)

Comprehensive income (loss)

 

(519

)

2,080

 

2,534

 

1,404

 

Less: Comprehensive income attributable to the non-controlling interest

 

836

 

3,058

 

4,661

 

4,087

 

Comprehensive loss attributable to Crosstex Energy, Inc.

 

$

(1,355

)

$

(978

)

$

(2,127

)

$

(2,683

)

 

See accompanying notes to condensed consolidated financial statements.

 

5



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Changes in Stockholders’ Equity

Six Months Ended June 30, 2012

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

Additional

 

Retained

 

Other

 

Non-

 

 

 

 

 

Common Stock

 

Paid in

 

Earning

 

Comprehensive

 

Controlling

 

 

 

 

 

Shares

 

Amount

 

Capital

 

(Deficit)

 

Income (loss)

 

Interest

 

Total

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Balance, December 31, 2011

 

47,194

 

$

471

 

$

244,211

 

$

(82,177

)

$

(85

)

$

666,827

 

$

829,247

 

Issuance of units by the Partnership to non-controlling

 

 

 

 

 

 

158,014

 

158,014

 

Stock-based compensation

 

 

 

2,397

 

 

 

2,716

 

5,113

 

Common dividends

 

 

 

 

(11,221

)

 

 

(11,221

)

Net (loss) income

 

 

 

 

(2,496

)

 

3,064

 

568

 

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

 

185

 

2

 

(629

)

 

 

 

(627

)

Hedging gains or losses reclassified to earnings

 

 

 

 

 

71

 

313

 

384

 

Adjustment in fair value of derivatives

 

 

 

 

 

298

 

1,284

 

1,582

 

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

 

 

 

 

 

 

(884

)

(884

)

Distribution to non-controlling interest

 

 

 

 

 

 

(32,584

)

(32,584

)

Changes in equity due to issuance of units by the Partnership

 

 

 

 

17,441

 

 

 

(12,305

)

5,136

 

Balance, June 30, 2012

 

47,379

 

$

473

 

$

263,420

 

$

(95,894

)

$

284

 

$

786,445

 

$

954,728

 

 

See accompanying notes to condensed consolidated financial statements.

 

6



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Consolidated Statements of Cash Flows

 

 

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

 

 

(Unaudited)

 

 

 

(In thousands)

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

568

 

$

1,808

 

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

 

 

 

 

 

Depreciation and amortization

 

65,085

 

61,326

 

Gain on sale of property

 

(504

)

(80

)

Deferred tax benefit

 

(1,871

)

(2,009

)

Non-cash stock-based compensation

 

5,113

 

4,115

 

Non-cash portion of derivatives (gain) loss

 

(5,975

)

828

 

Amortization of debt issue costs

 

1,321

 

4,065

 

Amortization of discount on notes

 

948

 

948

 

Equity in loss of limited liability company

 

 

236

 

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable, accrued revenue and other

 

24,991

 

(10,657

)

Natural gas and natural gas liquids, prepaid expenses and other

 

(8,971

)

(5,378

)

Accounts payable, accrued gas purchases and other accrued liabilities

 

(29,300

)

8,640

 

Net cash provided by operating activities

 

51,405

 

63,842

 

Cash flows from investing activities:

 

 

 

 

 

Additions to property and equipment

 

(90,046

)

(49,643

)

Proceeds from sale of property

 

632

 

107

 

Investment in limited liability company

 

(52,250

)

(35,000

)

Net cash used in investing activities

 

(141,664

)

(84,536

)

Cash flows from financing activities:

 

 

 

 

 

Proceeds from borrowings

 

548,500

 

277,250

 

Payments on borrowings

 

(335,500

)

(232,308

)

Increase in restricted cash

 

(245,100

)

 

Payments on capital lease obligations

 

(1,536

)

(1,510

)

(Decrease) increase in drafts payable

 

(5,985

)

3,165

 

Debt refinancing costs

 

(4,962

)

(3,792

)

Conversion of restricted stock, net of shares withheld for taxes

 

(629

)

(1,019

)

Distributions to non-controlling partners in the Partnership

 

(32,583

)

(27,320

)

Common dividend paid

 

(11,221

)

(8,192

)

Issuance of common units by the Partnership

 

158,014

 

 

Conversion of restricted units, net of units withheld for taxes

 

(980

)

(1,740

)

Proceeds from exercise of Partnership unit options

 

95

 

392

 

Net cash provided by financing activities

 

68,113

 

4,926

 

Net decrease in cash and cash equivalents

 

(22,146

)

(15,768

)

Cash and cash equivalents, beginning of period

 

30,343

 

22,780

 

Cash and cash equivalents, end of period

 

$

8,197

 

$

7,012

 

Cash paid for interest

 

$

36,252

 

$

35,936

 

Cash paid for income taxes

 

$

784

 

$

752

 

 

See accompanying notes to condensed consolidated financial statements.

 

7



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

June 30, 2012

(Unaudited)

 

(1) General

 

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

 

Crosstex Energy, Inc., a Delaware corporation formed on April 28, 2000, is engaged, through its subsidiaries, in the gathering, transmission, processing and marketing of natural gas, natural gas liquids (NGLs), and providing terminal services for crude oil. The Company connects the wells of natural gas producers in the geographic areas of its gathering systems in order to gather for a fee or purchase the gas production, processes natural gas for the removal of NGLs, transports natural gas and NGLs and ultimately provides natural gas and NGLs to a variety of markets.  The Company operates processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee arrangements. In addition, the Company purchases natural gas and NGLs from producers not connected to its gathering systems for resale and markets natural gas and NGLs on behalf of producers for a fee.  The Company recently added crude oil terminal facilities in south Louisiana to provide access for crude oil producers to the premium markets in this area.

 

The accompanying condensed consolidated financial statements include the assets, liabilities and results of operations of the Company, its majority owned subsidiaries and Crosstex Energy, L.P. (herein referred to as the Partnership or CELP), a publicly traded Delaware limited partnership.  The Partnership is included because CEI controls the general partner of the Partnership.

 

(a) Basis of Presentation

 

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

 

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

 

(b) Investment in Limited Liability Company

 

On June 22, 2011, the Partnership entered into a limited liability agreement with Howard Energy Partners (“HEP”) for an initial capital contribution of $35.0 million in exchange for an individual ownership interest in HEP. In 2012, the Partnership made an additional capital contribution of $52.3 million to HEP related to HEP’s acquisition of substantially all of Meritage Midstream Services’ natural gas gathering assets in south Texas. HEP owns midstream assets and provides midstream and construction services to Eagle Ford Shale producers.  The Partnership owns 30.6 percent of HEP and accounts for this investment under the equity method of accounting. This investment is reflected on the balance sheet as “Investment in limited liability company.”

 

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

 

Currently, the Partnership’s Sabine plant has a contract with a third-party to fractionate the raw-make NGLs produced by the Sabine plant.  The primary term of the contract expired on June 30, 2012 and is currently renewed on a month-to-month basis.  The Partnership will negotiate with this third-party to try to establish a long-term fractionation agreement. If this third-party ceases to fractionate the produced NGLs from the Sabine plant and the Partnership is unsuccessful in determining another alternative for its Sabine customers, the Partnership will cease operation of the Sabine plant.  Although the Partnership does not have specific plans at this time to relocate the Sabine plant if it is idled, the Partnership may utilize it elsewhere in its operations.  The net book value of the Sabine plant was $46.4 million (including $13.3 million of intangible assets attributable to customer relationships) as of June 30,

 

8



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

2012.  If the plant is idled on a long-term basis, an impairment may be recorded to expense the non-recoverable costs associated with the plant’s current location, which are estimated to be approximately $27.0 million based on the net book value as of June 30, 2012.

 

(d) Clearfield Acquisition

 

On July 2, 2012, the Partnership, through a wholly-owned subsidiary, completed its previously announced acquisition of all of the issued and outstanding common stock of Clearfield Energy, Inc. and Clearfield Energy’s wholly-owned subsidiaries (collectively, “Clearfield”). Clearfield is a well-established crude oil, condensate and water services company with operations in Ohio, Kentucky and West Virginia. Clearfield’s business includes crude oil pipelines, a barge loading terminal on the Ohio River, a rail loading terminal on the Ohio Central Railroad network, a trucking fleet, and brine water disposal wells.

 

The Partnership paid approximately $210.0 million in cash for the acquisition and the purchase was funded from restricted cash that resulted from the senior notes offering in May 2012. The assets associated with this acquisition will be included in a new reporting segment that will be referred to as Ohio River Valley. Pro-forma financial statements for the Clearfield acquisition are available on our amended Current Report on Form 8-K/A filed on August 1, 2012.

 

(2) Long-Term Debt

 

As of June 30, 2012 and December 31, 2011, long-term debt consisted of the following (in thousands):

 

 

 

June 30,

 

December 31,

 

 

 

2012

 

2011

 

Bank credit facility (due 2016), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2012 and December 31, 2011 was 3.33% and 2.9%, respectively

 

$

48,000

 

$

85,000

 

Senior unsecured notes (due 2018), net of discount of $10.6 million and $11.6 million, respectively, which bear interest at the rate of 8.875%

 

714,357

 

713,409

 

Senior unsecured notes (due 2022), which bear interest at the rate of 7.125%

 

250,000

 

 

 

 

1,012,357

 

798,409

 

Less current portion

 

(250,000

)

 

Debt classified as long-term

 

$

762,357

 

$

798,409

 

 

Credit Facility.  As of June 30, 2012, there was $57.6 million in outstanding letters of credit and $48.0 million borrowed under the Partnership’s bank credit facility, leaving approximately $529.4 million available for future borrowing based on the borrowing capacity of $635.0 million.

 

In January, 2012, the Partnership amended its credit facility.  This amendment increased its borrowing capacity from $485.0 million to $635.0 million and amended certain terms under the facility to provide additional financial flexibility during the remaining four-year term of the facility.

 

9



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

In May 2012, the Partnership amended its credit facility.  The amendment to the Partnership’s credit facility, among other things, (i) increased the maximum permitted consolidated leverage ratio (as defined in the amended credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) during the Clearfield acquisition period (as defined in the amended credit facility, being generally the four quarterly measurement periods after closing the Clearfield acquisition) from 5.0 to 1.0 to 5.5 to 1.0, and (ii) increased the maximum permitted consolidated leverage ratio during any other acquisition period (as defined in the amended credit facility, being generally the three quarterly measurement periods after closing certain material acquisitions) from 5.0 to 1.0 to 5.5 to 1.0.

 

The credit facility is guaranteed by substantially all of the Partnership’s subsidiaries and is secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors, including all material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of the Partnership’s equity interests in substantially all of its subsidiaries and its interest in HEP. The Partnership may prepay all loans under the amended credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.

 

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

 

2022 Notes.  On May 24, 2012, the Partnership issued $250.0 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022 at an issue price of 100% of the principal amount to yield 7.125% to maturity. The interest payments are due semi-annually in arrears in June and December.  The Partnership placed into escrow the net proceeds of $245.1 million from the offering of the 2022 Notes pending completion of the Clearfield acquisition. The net proceeds are classified as restricted cash as of June 30, 2012 and the 2022 Notes are classified as current debt as of June 30, 2012. Upon closing of the Clearfield acquisition on July 2, 2012, the 2022 Notes were reclassified as long term debt and the restricted cash was used to fund the Clearfield acquisition and for general partnership purposes, including capital expenditures for the Cajun-Sibon natural gas liquids pipeline expansion.

 

The Partnership may redeem up to 35% of the 2022 Notes at any time prior to June 1, 2015 with the cash proceeds from equity offerings at a redemption price of 107.125% of the principal amount of the 2022 Notes (plus accrued and unpaid interest to the redemption date).

 

Prior to June 1, 2017, the Partnership may redeem all or a part of the 2022 Notes at the redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest to the redemption date.

 

On or after June 1, 2017, the Partnership may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.563% for the twelve-month period beginning on June 1, 2017, 102.375% for the twelve-month period beginning on June 1, 2018, 101.188% for the twelve-month period beginning on June 1, 2019 and 100.000% for the twelve-month period beginning on June 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

 

Under the terms of the indenture governing the 2022 Notes, repurchase offer obligations would be triggered by a change of control combined with a ratings decline on the 2022 Notes. All other material terms of the senior unsecured notes are described in footnote 5 to the consolidated financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

 

(3) Other Long-term Liabilities

 

Prior to January 1, 2011, the Partnership entered into 9 and 10-year capital leases for certain equipment. Assets under capital leases as of June 30, 2012 are summarized as follows (in thousands):

 

Compressor equipment

 

$

37,199

 

Less: Accumulated amortization

 

(12,087

)

Net assets under capital leases

 

$

25,112

 

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

The following are the minimum lease payments to be made in each of the following years indicated for the capital leases in effect as of June 30, 2012 (in thousands):

 

2012

 

$

2,291

 

2013 through 2016 ($4,582 annually)

 

18,328

 

Thereafter

 

12,100

 

Less: Interest

 

(5,888

)

Net minimum lease payments under capital lease

 

26,831

 

Less: Current portion of net minimum lease payments

 

(4,448

)

Long-term portion of net minimum lease payments

 

$

22,383

 

 

(4) Certain Provisions of the Partnership Agreement

 

(a)          Partnership Distributions

 

Unless restricted by the terms of the Partnership’s credit facility and/or the indentures governing the Partnership’s 2022 Notes and the Partnership’s 8 7/8% senior unsecured notes due 2018 (“2018 Notes” and, together with the 2022 Notes, “all senior unsecured notes”), the Partnership must make distributions of 100.0% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98.0% to the common unitholders and 2.0% to the general partner, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved.

 

Under the quarterly incentive distribution provisions, generally the Partnership’s general partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23.0% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit. Incentive distributions totaling $1.1 million and $2.1 million were earned by the Company for the three and six months ended June 30, 2012, respectively.

 

The Partnership’s first quarter 2012 distribution on its common and preferred units of $0.33 per unit was paid on May 15, 2012. The Partnership’s second quarter 2012 distribution on its common and preferred units of $0.33 per unit will be paid on August 14, 2012.

 

(b)  Issuance of Partnership Equity

 

On May 15, 2012, the Partnership issued 10,200,000 common units representing limited partner interests in the Partnership at a public offering price of $16.28 per unit for net proceeds of $158.0 million. The net proceeds from the common units offering were used for general partnership purposes.

 

The Company reflects changes in its ownership interest in the Partnership as equity transactions.  The carrying amount of the non-controlling interest is adjusted to reflect the change in the Company’s ownership interest in the Partnership.  Any difference between the fair value of the consideration received and the amount by which the non-controlling interest is adjusted is recognized in additional paid-in capital.  The Company’s book carrying amount per Partnership unit was below the price per unit received by the Partnership for its May 2012 sale of common units resulting in a change in equity of $12.3 million.  The change was recorded as an increase in additional paid in capital and a reduction in non-controlling interest during the period ended June 30, 2012.  The Company also reduced its deferred tax liability in the amount of $5.1 million relating to the difference between its book and tax investment in the Partnership with the offset to additional paid-in-capital.

 

(5) Earnings per Share and Dilution Computations

 

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the six months ended June 30, 2012 and 2011.  The computation of diluted earnings per share further assumes the dilutive effect of common share options and restricted shares.  All common share equivalents were antidilutive in the six months ended June 30, 2012 and June 30, 2011 because the Company had a net loss for the periods.

 

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Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

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

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Net loss attributable to Crosstex Energy, Inc.

 

$

(1,672

)

$

(1,073

)

$

(2,496

)

$

(2,609

)

Distributed earnings allocated to:

 

 

 

 

 

 

 

 

 

Common shares

 

$

5,682

 

$

4,239

 

$

10,891

 

$

8,002

 

Unvested restricted shares

 

172

 

115

 

330

 

190

 

Total distributed earnings

 

$

5,854

 

$

4,354

 

$

11,221

 

$

8,192

 

Undistributed loss allocated to:

 

 

 

 

 

 

 

 

 

Common shares

 

$

(7,307

)

$

(5,281

)

$

(13,323

)

$

(10,546

)

Unvested restricted shares

 

(219

)

(146

)

(394

)

(255

)

Total undistributed loss

 

$

(7,526

)

$

(5,427

)

$

(13,717

)

$

(10,801

)

Net loss allocated to:

 

 

 

 

 

 

 

 

 

Common shares

 

$

(1,625

)

$

(1,042

)

$

(2,432

)

$

(2,544

)

Unvested restricted shares

 

(47

)

(31

)

(64

)

(65

)

Total net loss

 

$

(1,672

)

$

(1,073

)

$

(2,496

)

$

(2,609

)

Basic and diluted net loss per share:

 

 

 

 

 

 

 

 

 

Basic common share

 

$

(0.03

)

$

(0.02

)

$

(0.05

)

$

(0.05

)

Diluted common share

 

(0.03

)

(0.02

)

(0.05

)

(0.05

)

 

The following are the common share amounts used to compute the basic and diluted earnings per common share for the three and six months ended June 30, 2012 and 2011 (in thousands):

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Basic and diluted weighted average shares outstanding:

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding

 

47,366

 

47,140

 

47,361

 

47,108

 

 

(6) Employee Incentive Plans

 

(a)         Long-Term Incentive Plans

 

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

 

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

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

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

 

$

2,233

 

$

1,596

 

$

4,473

 

$

3,386

 

Cost of share-based compensation charged to operating expense

 

316

 

265

 

640

 

729

 

Total amount charged to income

 

$

2,549

 

$

1,861

 

$

5,113

 

$

4,115

 

Interest of non-controlling partners in share-based compensation

 

$

1,722

 

$

763

 

$

2,716

 

$

1,672

 

Amount of related income tax benefit recognized in income

 

$

306

 

$

407

 

$

887

 

$

906

 

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

(b) Partnership Restricted Units

 

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the six months ended June 30, 2012 is provided below:

 

 

 

Six Months Ended June 30, 2012

 

 

 

 

 

Weighted 
Average

 

 

 

Number of

 

Grant-Date

 

Crosstex Energy, L.P. Restricted Units:

 

Units

 

Fair Value

 

Non-vested, beginning of period

 

949,844

 

$

10.45

 

Granted

 

352,912

 

16.53

 

Vested*

 

(232,700

)

6.91

 

Forfeited

 

(13,954

)

12.73

 

Non-vested, end of period

 

1,056,102

 

$

13.23

 

Aggregate intrinsic value, end of period (in thousands)

 

$

17,320

 

 

 

 


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

 

The Partnership issued restricted units in 2012 to officers and other employees. These restricted units typically vest at the end of three years and are included in the restricted units outstanding and the current share-based compensation cost calculations at June 30, 2012.

 

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the three and six months ended June 30, 2012 and 2011 are provided below (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

Crosstex Energy, L.P. Restricted Units:

 

2012

 

2011

 

2012

 

2011

 

Aggregate intrinsic value of units vested

 

$

280

 

$

1,870

 

$

3,806

 

$

6,109

 

Fair value of units vested

 

$

281

 

$

2,383

 

$

1,608

 

$

5,556

 

 

As of June 30, 2012, there was $7.6 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.6 years.

 

(c) Partnership Unit Options

 

A summary of the unit option activity for the six months ended June 30, 2012 is provided below:

 

 

 

Six Months Ended June 30, 2012

 

 

 

 

 

Weighted

 

 

 

Number of

 

Average

 

Crosstex Energy, L.P. Unit Options:

 

Units

 

Exercise Price

 

Outstanding, beginning of period

 

451,574

 

$

6.99

 

Exercised

 

(40,246

)

5.06

 

Forfeited

 

(10,433

)

16.34

 

Outstanding, end of period

 

400,895

 

$

6.95

 

Options exercisable at end of period

 

334,326

 

 

 

Weighted average contractual term (years) end of period:

 

 

 

 

 

Options outstanding

 

6.7

 

 

 

Options exercisable

 

6.5

 

 

 

Aggregate intrinsic value end of period (in thousands):

 

 

 

 

 

Options outstanding

 

$

4,201

 

 

 

Options exercisable

 

$

3,508

 

 

 

 

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Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

A summary of the unit options intrinsic value exercised (market value in excess of exercise price at date of exercise) and fair value of units exercised (value per Black-Scholes-Merton option pricing model at date of grant) during the three and six months ended June 30, 2012 and June 30, 2011 are provided below (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

Crosstex Energy, L.P. Unit Options:

 

2012

 

2011

 

2012

 

2011

 

Intrinsic value of unit options exercised

 

$

67

 

$

479

 

$

478

 

$

985

 

Fair value of unit options vested

 

$

 

$

236

 

$

277

 

$

561

 

 

As of June 30, 2012, there was $0.1 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted average period of 0.5 years.

 

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

 

The Company’s restricted shares are valued at their fair value at the date of grant which is equal to the market value of the common stock on such date. A summary of the restricted share activities for the six months ended June 30, 2012 is provided below:

 

 

 

Six Months Ended

 

 

 

June 30, 2012

 

 

 

 

 

Weighted 
Average

 

Crosstex Energy, Inc. Restricted Shares:

 

Number of
Shares

 

Grant-Date 
Fair Value

 

Non-vested, beginning of period

 

1,221,351

 

$

7.40

 

Granted

 

454,146

 

13.28

 

Vested*

 

(244,195

)

5.18

 

Forfeited

 

(18,850

)

8.60

 

Non-vested, end of period

 

1,412,452

 

$

9.66

 

Aggregate intrinsic value, end of period (in thousands)

 

$

19,774

 

 

 

 


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

 

CEI issued restricted shares in 2012 to officers and other employees. These restricted shares typically vest at the end of three years and are included in restricted shares outstanding and the current share-based compensation cost calculations at June 30, 2012.

 

A summary of the restricted shares’ aggregate intrinsic value (market value at vesting date) and fair value of shares vested (market value at date of grant) during the three and six months ended June 30, 2012 and June 30, 2011 are provided below (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

Crosstex Energy, Inc. Restricted Shares:

 

2012

 

2011

 

2012

 

2011

 

Aggregate intrinsic value of shares vested

 

$

391

 

$

1,111

 

$

3,127

 

$

3,689

 

Fair value of shares vested

 

$

260

 

$

2,391

 

$

1,266

 

$

5,281

 

 

As of June 30, 2012 there was $7.6 million of unrecognized compensation costs related to CEI non-vested restricted shares. The cost is expected to be recognized over a weighted average period of 1.6 years.

 

14



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

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

 

CEI stock options have not been granted as a means of compensation since 2005. All options outstanding at December 31, 2009 were vested and exercisable with all associated costs recognized.  The following is a summary of the CEI stock options outstanding as of June 30, 2012:

 

 

 

Six Months Ended June 30, 2012

 

 

 

 

 

Weighted

 

 

 

Number of

 

Average

 

Crosstex Energy, Inc. Stock Options:

 

Shares

 

Exercise Price

 

Outstanding, beginning of period

 

37,500

 

$

6.50

 

Forfeited

 

 

 

Outstanding, end of period

 

37,500

 

$

 

Options exercisable at end of period

 

37,500

 

$

 

 

(7) Derivatives

 

Commodity Swaps

 

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

 

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

 

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

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

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

 

$

(7,095

)

$

(825

)

$

(5,913

)

$

730

 

Realized losses on derivatives

 

2,213

 

2,368

 

3,238

 

4,128

 

Ineffective portion of derivatives qualifying for hedge accounting

 

(23

)

(101

)

(61

)

(82

)

Net (gains) losses related to commodity swaps

 

$

(4,905

)

$

1,442

 

$

(2,736

)

$

4,776

 

Put option premium mark to market

 

 

94

 

 

181

 

(Gains) losses on derivatives

 

$

(4,905

)

$

1,536

 

$

(2,736

)

$

4,957

 

 

15



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

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

 

 

 

June 30,

 

December 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Fair value of derivative assets — current, designated

 

$

1,568

 

$

151

 

Fair value of derivative assets — current, non-designated

 

5,112

 

2,716

 

Fair value of derivative assets — long term, designated

 

125

 

 

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

 

1,479

 

 

Fair value of derivative liabilities — current, designated

 

 

(702

)

Fair value of derivative liabilities — current, non-designated

 

(2,839

)

(4,885

)

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

 

(7

)

 

Net fair value of derivatives

 

$

5,438

 

$

(2,720

)

 

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets as of June 30, 2012 (all gas volumes are expressed in MMBtu’s and liquids volumes are expressed in gallons). The remaining term of the contracts extend no later than December 2013 for derivatives. Changes in the fair value of the Partnership’s mark to market derivatives are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings. The ineffective portion is recorded in earnings immediately.

 

 

 

June 30, 2012

 

Transaction Type

 

Volume

 

Fair Value

 

 

 

(In thousands)

 

Cash Flow Hedges:*

 

 

 

 

 

Liquids swaps (short contracts)

 

(5,705

)

$

1,693

 

Total swaps designated as cash flow hedges

 

 

 

$

1,693

 

 

 

 

 

 

 

Mark to Market Derivatives:*

 

 

 

 

 

Swing swaps (long contracts)

 

419

 

$

3

 

Physical offsets to swing swap transactions (short contracts)

 

(419

)

 

Swing swaps (short contracts)

 

(4,588

)

(35

)

Physical offsets to swing swap transactions (long contracts)

 

4,588

 

 

 

 

 

 

 

 

Basis swaps (long contracts)

 

2,501

 

(30

)

Physical offsets to basis swap transactions (short contracts)

 

(2,501

)

5,189

 

Basis swaps (short contracts)

 

(2,501

)

15

 

Physical offsets to basis swap transactions (long contracts)

 

2,501

 

(6,624

)

 

 

 

 

 

 

Third-party on-system swaps (long contracts)

 

155

 

 

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

 

(155

)

(22

)

 

 

 

 

 

 

Processing margin hedges — liquids (short contracts)

 

(9,064

)

4,210

 

Processing margin hedges — gas (long contracts)

 

1,188

 

(1,035

)

Processing margin hedges — gas (short contracts)

 

(187

)

240

 

 

 

 

 

 

 

Liquids swaps - non-designated (short contracts)

 

(4,393

)

1,471

 

 

 

 

 

 

 

Storage swap transactions — gas (long contracts)

 

210

 

116

 

Storage swap transactions — gas (short contracts)

 

(290

)

62

 

Storage swap transactions — liquids inventory (long contracts)

 

1,470

 

(25

)

Storage swap transactions — liquids inventory (short contracts)

 

(4,830

)

210

 

 

 

 

 

 

 

Total mark to market derivatives

 

 

 

$

3,745

 

 


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

 

On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements (ISDAs) with its counterparties. If the Partnership’s counterparties failed to perform under existing swap contracts, entered into under these ISDAs, the Partnership’s maximum loss as of June 30, 2012 of $13.5 million would be reduced to $12.1 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

 

16



Table of Contents

 

CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

Impact of Cash Flow Hedges

 

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

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

Increase (Decrease) in Midstream Revenue

 

2012

 

2011

 

2012

 

2011

 

Liquids realized loss included in Midstream revenue

 

$

407

 

$

(1,048

)

$

395

 

$

(1,708

)

 

Natural Gas

 

As of June 30, 2012, the Partnership has no balances in accumulated other comprehensive income related to natural gas.

 

Liquids

 

As of June 30, 2012, an unrealized derivative fair value net gain of $1.7 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income. Of that amount, a net gain of $1.6 million is expected to be reclassified into earnings through June 2013. The actual reclassification to earnings will be based on mark to market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected in the above table.

 

Derivatives Other Than Cash Flow Hedges

 

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

 

 

 

Maturity Periods

 

 

 

Less than one year

 

One to two years

 

More than two years

 

Total fair value

 

June 30, 2012

 

$

2,272

 

$

1,473

 

$

 

$

3,745

 

 

(8)      Fair Value Measurements

 

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

 

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

 

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

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

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

 

 

 

June 30, 2012

 

December 31, 2011

 

 

 

Level 2

 

Level 2

 

Commodity Swaps*

 

$

5,438

 

$

(2,720

)

Total

 

$

5,438

 

$

(2,720

)

 


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

 

Fair Value of Financial Instruments

 

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

 

 

 

June 30, 2012

 

December 31, 2011

 

 

 

Carrying

 

Fair

 

Carrying

 

Fair

 

 

 

Value

 

Value

 

Value

 

Value

 

Fair value of 2022 Notes classified as current debt

 

$

250,000

 

$

246,720

 

$

 

$

 

Long-term debt

 

$

762,357

 

$

816,500

 

$

798,409

 

$

882,500

 

Obligations under capital lease

 

$

26,831

 

$

28,847

 

$

28,367

 

$

27,637

 

 

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

 

The Partnership had $ 48.0 million in borrowings under its revolving credit facility included in long-term debt as of June 30, 2012 and $85.0 million at December 31, 2011. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of June 30, 2012 and December 31, 2011, the Partnership also had borrowings totaling $714.4 million and $713.4 million, net of discount, respectively, under the 2018 Notes with a fixed rate of 8.875% and $250.0 million as of June 30, 2012 under the 2022 Notes with a fixed rate of 7.125%.  The fair value of all senior unsecured notes as of June 30, 2012 and December 31, 2011 was based on Level 1 inputs from third-party market quotations.  The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks.

 

(9) Income Tax

 

The income tax provision for the six months ended June 30, 2012 reflects a tax benefit of $0.8 million for the current period loss. Unrecognized tax benefits increased $0.4 million during the six months ended June 30, 2012, and the increase, if recognized, would affect the effective tax rate.

 

The Company had recorded a deferred tax asset in the amount of $20.5 million and $10.8 million relating to the difference between its book and tax basis of its investment in the Partnership as of December 31, 2011 and June 30, 2012, respectively. Because the Company can only realize this deferred tax asset upon liquidation of the Partnership and to the extent of capital gains, the Company has provided a full valuation allowance against this deferred tax asset. The deferred tax asset and the related valuation allowance decreased by $9.7 million during the second quarter of 2012 due to the Partnership’s issuance of common units.

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

(10) Commitments and Contingencies

 

(a) Employment and Severance Agreements

 

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

 

(b) Environmental Issues

 

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

 

(c) Other

 

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

 

On June 7, 2010, Formosa Plastics Corporation, Texas, Formosa Plastics Corporation, America, Formosa Utility Venture, Ltd., and Nan Ya Plastics Corporation, America filed a lawsuit against Crosstex Energy, Inc., Crosstex Energy, L.P., Crosstex Energy GP, L.P., Crosstex Energy GP, LLC, Crosstex Energy Services, L.P., and Crosstex Gulf Coast Marketing, Ltd. in the 24th Judicial District Court of Calhoun County, Texas, asserting claims for negligence, res ipsa loquitor, products liability and strict liability relating to the alleged receipt by the plaintiffs of natural gas liquids into their facilities from facilities operated by the Partnership.  The amended petition alleges that the plaintiffs have incurred at least $35.0 million in damages, including damage to equipment and lost profits.  The Partnership has submitted the claim to its insurance carriers and intends to vigorously defend the lawsuit.  The Partnership believes that any recovery would be within applicable policy limits. Although it is not possible to predict the ultimate outcome of this matter, the Partnership does not expect that an award in this matter will have a material adverse impact on its consolidated results of operations or financial condition.

 

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

 

The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas.  In January 2012, a plaintiff in one of these lawsuits was awarded a judgment of $2.0 million.  The Partnership has appealed the matter and has posted a bond to secure the judgment pending its resolution.  The Partnership has accrued $2.0 million related to this matter and reflected the related

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

expense in operating expenses in the fourth quarter of 2011.  Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

 

(11) Segment Information

 

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

 

The Partnership evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general partnership expenses associated with managing all reportable operating segments and the Company’s general and administrative expenses, including the Partnership’s general and administrative expenses. Corporate assets consist primarily of property and equipment, including software, for general corporate support, working capital, debt financing costs, the investment in HEP, and as of June 30, 2012, $245.1 million in restricted cash. (See note 2 in these notes to condensed consolidated financial statements for additional discussion of the restricted cash)

 

Summarized financial information concerning the Partnership’s reportable segments as consolidated into the Company’s condensed financial statements is shown in the following table.

 

 

 

LIG

 

NTX

 

PNGL

 

Corporate

 

Totals

 

 

 

(In thousands)

 

Three Months Ended June 30, 2012:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

121,479

 

$

61,236

 

$

168,479

 

$

 

$

351,194

 

Sales to affiliates

 

60,415

 

17,227

 

40,243

 

(117,885

)

 

Purchased gas and NGLs

 

(153,601

)

(31,457

)

(193,717

)

117,885

 

(260,890

)

Operating expenses

 

(8,759

)

(14,144

)

(7,668

)

 

(30,571

)

Segment profit

 

$

19,534

 

$

32,862

 

$

7,337

 

$

 

$

59,733

 

Gain (loss) on derivatives

 

$

4,541

 

$

(153

)

$

517

 

$

 

$

4,905

 

Depreciation, amortization and impairments

 

$

(3,200

)

$

(21,009

)

$

(8,069

)

$

(611

)

$

(32,889

)

Capital expenditures

 

$

1,886

 

$

20,295

 

$

30,255

 

$

1,076

 

$

53,512

 

Identifiable assets

 

$

280,090

 

$

1,086,299

 

$

498,888

 

$

383,160

 

$

2,248,437

 

Three Months Ended June 30, 2011:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

219,479

 

$

87,813

 

$

218,443

 

$

 

$

525,735

 

Sales to affiliates

 

23,728

 

21,295

 

207

 

(45,230

)

 

Purchased gas and NGLs

 

(211,417

)

(64,360

)

(198,630

)

45,230

 

(429,177

)

Operating expenses

 

(8,902

)

(12,108

)

(6,903

)

 

(27,913

)

Segment profit

 

$

22,888

 

$

32,640

 

$

13,117

 

$

 

$

68,645

 

(Loss) gain on derivatives

 

$

(1,269

)

$

(377

)

$

110

 

$

 

$

(1,536

)

Depreciation, amortization and impairments

 

$

(4,045

)

$

(18,744

)

$

(7,828

)

$

(1,037

)

$

(31,654

)

Capital expenditures

 

$

1,129

 

$

16,807

 

$

5,555

 

$

715

 

$

24,206

 

Identifiable assets

 

$

327,174

 

$

1,112,750

 

$

492,920

 

$

78,345

 

$

2,011,189

 

Six Months Ended June 30, 2012:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

268,177

 

$

125,917

 

$

328,809

 

$

 

$

722,903

 

Sales to affiliates

 

133,225

 

48,711

 

85,787

 

(267,723

)

 

Purchased gas and NGLs

 

(342,822

)

(81,478

)

(376,269

)

267,723

 

(532,846

)

Operating expenses

 

(16,696

)

(27,295

)

(14,387

)

 

(58,378

)

Segment profit

 

$

41,884

 

$

65,855

 

$

23,940

 

$

 

$

131,679

 

Gain (loss) on derivatives

 

$

4,643

 

$

(2,416

)

$

509

 

$

 

$

2,736

 

Depreciation, amortization and impairments

 

$

(6,372

)

$

(41,442

)

$

(16,028

)

$

(1,243

)

$

(65,085

)

Capital expenditures

 

$

1,888

 

$

33,451

 

$

45,917

 

$

1,536

 

$

82,792

 

Identifiable assets

 

$

280,090

 

$

1,086,299

 

$

498,888

 

$

383,160

 

$

2,248,437

 

Six Months Ended June 30, 2011:

 

 

 

 

 

 

 

 

 

 

 

Sales to external customers

 

$

424,397

 

$

168,779

 

$

422,329

 

$

 

$

1,015,505

 

Sales to affiliates

 

46,050

 

42,880

 

692

 

(89,622

)

 

Purchased gas and NGLs

 

(406,920

)

(127,519

)

(384,294

)

89,622

 

(829,111

)

Operating expenses

 

(16,969

)

(23,460

)

(12,528

)

 

(52,957

)

Segment profit

 

$

46,558

 

$

60,680

 

$

26,199

 

$

 

$

133,437

 

(Loss) gain on derivatives

 

$

(3,954

)

$

(1,094

)

$

91

 

$

 

$

(4,957

)

Depreciation, amortization and impairments

 

$

(7,205

)

$

(36,464

)

$

(15,541

)

$

(2,116

)

$

(61,326

)

Capital expenditures

 

$

2,679

 

$

35,011

 

$

9,636

 

$

1,202

 

$

48,528

 

Identifiable assets

 

$

327,174

 

$

1,112,750

 

$

492,919

 

$

78,346

 

$

2,011,189

 

 

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CROSSTEX ENERGY, INC.

 

Notes to Condensed Consolidated Financial Statements

 

The following table reconciles the segment profits reported above to the operating income as reported in the condensed

consolidated statements of operations (in thousands):

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Segment profits

 

$

59,733

 

$

68,645

 

131,679

 

133,437

 

General and administrative expenses

 

(13,774

)

(13,272

)

(29,380

)

(25,754

)

Gain (loss) on derivatives

 

4,905

 

(1,536

)

2,736

 

(4,957

)

Gain on sale of property

 

406

 

60

 

504

 

80

 

Depreciation, amortization and impairments

 

(32,889

)

(31,654

)

(65,085

)

(61,326

)

Operating income

 

$

18,381

 

$

22,243

 

40,454

 

41,480

 

 

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

 

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

 

Overview

 

Crosstex Energy, Inc. is a Delaware corporation formed on April 28, 2000 to engage in the gathering, transmission, processing, marketing of natural gas and natural gas liquids (NGLs) and providing terminal services for crude oil through its subsidiaries. Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, processing, transmission and marketing of natural gas, NGLs, and providing terminal services for crude oil.  These partnership interests consist of (i) 16,414,830 common units, representing approximately 22.0% of the limited partner interests in Crosstex Energy, L.P., and (ii) 100% ownership interest in Crosstex Energy GP, LLC, the general partner of Crosstex Energy, L.P., which owns a 2.0% general partner interest and all of the incentive distribution rights in Crosstex Energy, L.P.

 

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

 

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries.  We have no separate operating activities apart from those conducted by the Partnership, and our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own.  Our condensed consolidated results of

 

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operations are derived from the results of operations of the Partnership and also include our deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operation.  Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership.

 

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

 

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

 

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

 

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

 

·                  processing natural gas at its processing plants;

 

·                  fractionating and marketing the recovered NGLs;

 

·                  providing compression services; and

 

·                  providing crude oil terminal services.

 

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

 

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

 

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into the Delivery Contract, there has been both (1) a reduction in the gas available under the supply contracts and (2) the discovery of other shale reserves, most notably the Haynesville and the Marcellus Shales, which has increased the supplies available to east coast markets and reduced the basis spread between north Texas-area production and the market indices used in the Delivery Contract.  Due to these factors, the Partnership has had to purchase a portion of the gas necessary to fulfill its obligations under the Delivery Contract at market prices, resulting in negative margins under the Delivery Contract.

 

The Partnership has recorded a loss of approximately $8.5 million during the six months ended June 30, 2012 on the Delivery Contract.  The Partnership currently expects that it will record an additional loss of approximately $8.5 million to $10.5 million on the Delivery Contract for the remainder of the year ending December 31, 2012.  This estimate is based on forward prices, basis spreads and other market assumptions as of June 30, 2012. These assumptions are subject to change if market conditions change during the remainder of 2012, and actual results under the Delivery Contract in 2012 could be substantially different from the Partnership’s current estimates, which may result in a greater loss than currently estimated.

 

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

 

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

 

Recent Developments

 

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

 

In May 2012, the Partnership amended its credit facility.  The amendment to its credit facility, among other things, (i) increased the maximum permitted consolidated leverage ratio (as defined in the amended credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) during the Clearfield acquisition period (as defined in the amended credit facility, being generally the four quarterly measurement periods after closing the Clearfield Acquisition) from 5.0 to 1.0 to 5.5 to 1.0, and (ii) increased the maximum permitted consolidated leverage ratio during any other acquisition period (as defined in the amended credit facility, being generally the three quarterly measurement periods after closing certain material acquisitions) from 5.0 to 1.0 to 5.5 to 1.0.

 

Issuance of Partnership Equity. On May 15, 2012, the Partnership issued 10,200,000 common units representing limited partner interests in the Partnership at a public offering price of $16.28 per unit for net proceeds of $158.0 million. The net proceeds from the common units offering were used for general partnership purposes.

 

2022 Notes.  On May 24, 2012, the Partnership issued $250.0 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022 at an issue price of 100% of the principal amount to yield 7.125% to maturity. The interest payments are due semi-annually in arrears in June and December.  The Partnership placed into escrow the net proceeds of $245.1 million from the offering of the 2022 Notes pending completion of the Clearfield acquisition. The net proceeds are classified as restricted cash as of June 30, 2012 and the 2022 Notes are classified as current debt as of June 30, 2012. Upon closing of the Clearfield acquisition on July 2, 2012, the 2022 Notes were reclassified as long term debt and the restricted cash was used to fund the acquisition and for general partnership purposes, including capital expenditures for the Cajun-Sibon natural gas liquids pipeline expansion.

 

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Investment in Limited Liability Company.  On June 22, 2011, the Partnership entered into a limited liability agreement with Howard Energy Partners (“HEP”) for an initial capital contribution of $35.0 million in exchange for an individual ownership interest in HEP. In 2012, the Partnership made an additional capital contribution of $52.3 million to HEP related to HEP’s acquisition of substantially all of Meritage Midstream Services’ natural gas gathering assets in south Texas. HEP owns midstream assets and provides midstream and construction services to Eagle Ford Shale producers.  The Partnership owns 30.6 percent of HEP and accounts for this investment under the equity method of accounting. This investment is reflected on the balance sheet as “Investment in limited liability company.”

 

Clearfield Acquisition.  On July 2, 2012, the Partnership completed its previously announced acquisition of all of the issued and outstanding common stock of Clearfield Energy, Inc. and Clearfield Energy’s wholly-owned subsidiaries (collectively, “Clearfield”). Clearfield is a crude oil, condensate and water services company with operations in Ohio, Kentucky and West Virginia.

 

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

 

The Partnership paid approximately $210.0 million in cash for the acquisition and the acquisition was funded from restricted cash that resulted from the 2022 Notes offering. The assets associated with this acquisition will be included in a new reporting segment that will be referred to as Ohio River Valley. Pro-forma financial statements for the Clearfield acquisition are available our amended Current Report on Form 8-K/A filed on August 1, 2012.

 

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

 

Non-GAAP Financial Measures

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

(In millions)