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EX-31.1 - EXHIBIT 31.1 - CROSSTEX ENERGY INCc91954exv31w1.htm
EX-32.1 - EXHIBIT 32.1 - CROSSTEX ENERGY INCc91954exv32w1.htm
EX-31.2 - EXHIBIT 31.2 - CROSSTEX ENERGY INCc91954exv31w2.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
     
þ   Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2009
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
(State of organization)
  52-2235832
(I.R.S. Employer Identification No.)
     
2501 CEDAR SPRINGS
DALLAS, TEXAS

(Address of principal executive offices)
 
75201
(Zip Code)
(214) 953-9500
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o (Do not check if a smaller reporting company)   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
As of October 30, 2009, the Registrant had 46,502,477 shares of common stock outstanding.
 
 

 

 


 

TABLE OF CONTENTS
                 
Item     DESCRIPTION   Page  
       
 
       
       
PART I—FINANCIAL INFORMATION
       
       
 
       
1.      
Financial Statements
    3  
       
 
       
2.           28  
       
 
       
3.           39  
       
 
       
4.           42  
       
 
       
               
       
 
       
1.           42  
       
 
       
1A.           42  
       
 
       
6.           43  
       
 
       
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1

 

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CROSSTEX ENERGY, INC.
Condensed Consolidated Balance Sheets
                 
    September 30,     December 31,  
    2009     2008  
    (Unaudited)        
    (In thousands)  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 11,410     $ 13,959  
Accounts and notes receivable, net:
               
Trade, accrued revenue and other
    168,452       353,364  
Fair value of derivative assets
    10,422       27,166  
Natural gas and natural gas liquids, prepaid expenses and other
    11,310       9,658  
 
           
Total current assets
    201,594       404,147  
 
           
Assets held for sale
    183,528        
Property and equipment, net of accumulated depreciation of $239,519 and $296,671, respectively
    1,239,665       1,528,490  
Fair value of derivative assets
    8,701       4,628  
Intangible assets, net of accumulated amortization of $106,422 and $89,231, respectively
    544,288       578,096  
Goodwill
          19,673  
Other assets, net
    13,129       11,709  
 
           
Total assets
  $ 2,190,905     $ 2,546,743  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable, drafts payable and accrued gas purchases
  $ 127,723     $ 322,722  
Fair value of derivative liabilities
    24,561       28,506  
Current portion of long-term debt
    21,279       9,412  
Other current liabilities
    50,785       63,938  
 
           
Total current liabilities
    224,348       424,578  
 
           
Liabilities of assets held for sale
    9,419        
Long-term debt
    1,064,403       1,254,294  
Obligations under capital lease
    21,327       24,708  
Deferred tax liability
    90,109       81,998  
Fair value of derivative liabilities
    17,879       22,775  
Commitments and contingencies
           
Stockholders’ equity including non-controlling interest
    763,420       738,390  
 
           
Total liabilities and stockholders’ equity
  $ 2,190,905     $ 2,546,743  
 
           
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.
Consolidated Statements of Operations
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
    (Unaudited)  
    (In thousands, except per share amounts)  
Revenues:
                               
Midstream
  $ 349,194     $ 854,335     $ 1,049,451     $ 2,650,121  
Profit on energy trading activities
    1,504       647       3,645       2,331  
 
                       
Total revenues
    350,698       854,982       1,053,096       2,652,452  
 
                       
 
                               
Operating costs and expenses:
                               
Purchased gas
    269,461       775,782       824,812       2,411,025  
Operating expenses
    29,027       34,409       84,733       93,702  
General and administrative
    16,674       16,820       45,639       50,055  
Gain on sale of property
    (356 )     (4 )     (899 )     (1,023 )
Gain on derivatives
    (1,672 )     (2,460 )     (6,723 )     (4,286 )
Depreciation and amortization
    31,174       26,923       90,880       79,302  
 
                       
Total operating costs and expenses
    344,308       851,470       1,038,442       2,628,775  
 
                       
Operating income
    6,390       3,512       14,654       23,677  
Other income (expense):
                               
Interest expense, net
    (26,555 )     (14,210 )     (64,832 )     (32,751 )
Loss on extinguishment of debt
                (4,669 )      
Other income
    575       174       784       7,755  
 
                       
Total other income (expense)
    (25,980 )     (14,036 )     (68,717 )     (24,996 )
 
                       
Loss from continuing operations before income taxes and gain on issuance of Partnership units
    (19,590 )     (10,524 )     (54,063 )     (1,319 )
Income tax benefit (provision)
    2,462       (1,204 )     2,406       (7,743 )
Gain on issuance of Partnership units
                      14,748  
 
                       
Income (loss) from continuing operations, net of tax
    (17,128 )     (11,728 )     (51,657 )     5,686  
Income (loss) from discontinued operations, net of tax
    (3,361 )     5,302       3,812       18,541  
Gain from sale of discontinued operations, net of tax
    84,827             84,827        
 
                       
Net income
    64,338       (6,426 )     36,982       24,227  
 
                       
Less: Interest of non-controlling partners in the Partnership’s net income (loss):
                               
Interest of non-controlling partners in the Partnership’s continuing operations
    (12,231 )     (10,808 )     (32,852 )     (17,790 )
Interest of non-controlling partners in the Partnership’s discontinued operations
    (2,342 )     3,842       2,851       13,319  
Interest of non-controlling partners in the Partnership’s gain on sale of discontinued operations
    63,445             63,445        
 
                       
Total interest of non-controlling partners in the Partnership’s net income (loss)
    48,872       (6,966 )     33,444       (4,471 )
 
                       
Net income attributable to Crosstex Energy, Inc.
  $ 15,466     $ 540     $ 3,538     $ 28,698  
 
                       
Net income per common share:
                               
Basic and diluted
  $ 0.33     $ 0.01     $ 0.08     $ 0.61  
 
                       
Weighted average shares outstanding:
                               
Basic
    46,488       46,299       46,462       46,285  
 
                       
Diluted
    46,550       46,649       46,515       46,626  
 
                       
Amounts attributable to Crosstex Energy, Inc. common shareholders:
                               
Income (loss) from continuing operations, net of tax and non-controlling interest
  $ (4,897 )   $ (921 )   $ (18,805 )   $ 23,477  
Income (loss) from discontinued operations, net of tax and non-controlling interest
    (1,019 )     1,461       961       5,221  
Gain on sale of discontinued operations, net of tax and non- controlling interest
    21,382             21,382        
 
                       
Net income attributable to Crosstex Energy, Inc.
  $ 15,466     $ 540     $ 3,538     $ 28,698  
 
                       
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.
Consolidated Statements of Changes in Stockholders’ Equity
Nine Months Ended September 30, 2009
                                                         
                                    Accumulated                
                    Additional     Retained     Other             Total  
    Common Stock     Paid-In     Earnings     Comprehensive     Non-Controlling     Stockholders’  
    Shares     Amount     Capital     Deficit     Income (Loss)     Interest     Equity  
    (Unaudited)  
    (In thousands)  
 
Balance, December 31, 2008
    46,342     $ 464     $ 268,988     $ (54,693 )   $ 670     $ 522,961     $ 738,390  
Offering costs
                (42 )                       (42 )
Dividends paid
                      (4,228 )                 (4,228 )
Stock-based compensation
                2,286                   4,051       6,337  
Net income
                      3,538             33,444       36,982  
Conversion of restricted stock to common, net of shares withheld for taxes
    150             (310 )                 (134 )     (444 )
Hedging gains or losses reclassified to earnings
                            (1,215 )     (3,758 )     (4,973 )
Adjustment in fair value of derivatives
                            (241 )     (780 )     (1,021 )
Distribution to non-controlling interest
                                    (7,581 )     (7,581 )
 
                                         
Balance, September 30, 2009
    46,492     $ 464     $ 270,922     $ (55,383 )   $ (786 )   $ 548,203     $ 763,420  
 
                                         
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.
Consolidated Statements of Comprehensive Income
                                 
    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
    2009     2008     2009     2008  
    (Unaudited)  
    (In thousands)  
 
Net income (loss)
  $ 64,338     $ (6,426 )   $ 36,982     $ 24,227  
Non-controlling partners’ share of other comprehensive income in the Partnership
                      431  
Hedging gains (losses) reclassified to earnings
    34       1,898       (1,215 )     4,545  
Adjustment in fair value of derivatives
    21       4,489       (241 )     (2,385 )
 
                       
Comprehensive income
    64,393       (39 )     35,526       26,818  
Comprehensive income (loss) attributable to non-controlling interest
    48,872       (6,966 )     33,444       (4,471 )
 
                       
Comprehensive income (loss) attributable to Crosstex Energy, Inc.
  $ 15,521     $ 6,927     $ 2,082     $ 31,289  
 
                       
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.
Consolidated Statements of Cash Flows
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (Unaudited)  
    (In thousands)  
Cash flows from operating activities:
               
Net income
  $ 36,982     $ 24,227  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    101,530       98,752  
Gain on sale of property
    (98,361 )     (1,591 )
Deferred tax expense
    8,968       9,237  
Non-cash stock-based compensation
    6,337       8,261  
Amortization of debt issue costs
    7,654       2,055  
Gain on issuance of units of the Partnership
          (14,748 )
Non-cash derivatives gain
    (3,021 )     (2,216 )
Non-cash loss on debt extinguishment
    4,669        
Interest paid-in-kind
    6,042        
Changes in assets and liabilities:
               
Accounts receivable, accrued revenue and other
    168,095       38,515  
Natural gas, natural gas liquids, prepaid expenses and other
    (1,768 )     (4,821 )
Accounts payable, accrued gas purchases and other accrued liabilities
    (176,030 )     57,895  
 
           
Net cash provided by operating activities
    61,097       215,566  
 
           
Cash flows from investing activities:
               
Additions to property and equipment
    (90,793 )     (217,868 )
Insurance recoveries on property and equipment
    9,687        
Proceeds from sale of property
    245,276       3,775  
 
           
Net cash provided (used) by investing activities
    164,170       (214,093 )
 
           
Cash flows from financing activities:
               
Proceeds from borrowings
    489,943       1,357,260  
Payments on borrowings
    (673,470 )     (1,245,508 )
Proceeds from capital lease obligations
    1,486       18,348  
Payments on capital lease obligations
    (1,867 )     (789 )
Decrease in drafts payable
    (17,871 )     (28,931 )
Debt refinancing costs
    (13,784 )     (369 )
Distributions to non-controlling partners in the Partnership
    (7,581 )     (47,856 )
Common dividends paid
    (4,228 )     (46,973 )
Proceeds from exercised common stock options
          244  
Conversion of restricted units, net of units withheld for taxes
    (134 )     (1,373 )
Conversion of restricted stock, net of shares withheld for taxes
    (310 )     (3,711 )
Net proceeds from issuance of units of the Partnership
          99,928  
Proceeds from exercise of Partnership unit options
          729  
Contributions from non-controlling partners in the Partnership
          109  
 
           
Net cash provided (used) by financing activities
    (227,816 )     101,108  
 
           
Net increase (decrease) in cash and cash equivalents
    (2,549 )     102,581  
Cash and cash equivalents, beginning of period
    13,959       7,853  
 
           
Cash and cash equivalents, end of period
  $ 11,410     $ 110,434  
 
           
Cash paid for interest
  $ 64,985     $ 55,636  
Cash paid for income taxes
  $ 937     $ 1,229  
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements
September 30, 2009
(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.
CEI, a Delaware corporation formed on April 28, 2000, is engaged, through its subsidiaries, in the gathering, transmission, processing and marketing of natural gas and natural gas liquids (NGLs). The Company connects the wells of natural gas producers in the geographic areas of its gathering systems in order to gather for a fee or purchase the gas production, processes natural gas for the removal of NGLs, transports natural gas and NGLs and ultimately provides natural gas and NGLs to a variety of markets. In addition, the Company purchases natural gas and NGLs from producers not connected to its gathering systems for resale and markets natural gas and NGLs on behalf of producers for a fee.
The accompanying condensed consolidated financial statements include the assets, liabilities and results of operations of the Company, its majority owned subsidiaries and Crosstex Energy, L.P. (herein referred to as the Partnership or CELP), a publicly traded Delaware limited partnership. The Partnership is included because CEI controls the general partner of the Partnership.
The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to the consolidated financial statements for the prior years 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, 2008.
(a) Management’s Use of Estimates
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) Recent Accounting Pronouncements
Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) 805 and FASB ASC 810-10-65-1 were issued December 2007. FASB ASC 805 requires most identifiable assets, liabilities, non-controlling interests and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under FASB ASC 805, all business combinations will be accounted for by applying the acquisition method. FASB ASC 805 is effective for periods beginning on or after December 15, 2008. FASB ASC 810-10-65-1 requires non-controlling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. FASB ASC 810-10-65-1 was adopted January 1, 2009 and comparative period information has been recast to classify non-controlling interests in equity and attribute net income and other comprehensive income to non-controlling interests.
FASB ASC 815-10-65-1 was issued March 2008 and requires entities to provide greater transparency about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for under FASB ASC 815 and how the instruments and related hedged items affect the financial position, results of operations and cash flows of the entity. FASB ASC 815-10-65-1 is effective for fiscal years beginning after November 15, 2008. FASB ASC 815-10-65-1 was adopted effective January 1, 2009. Required disclosures were added to Note 8.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
FASB ASC 105 was released July 1, 2009 and intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements of non-governmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America. SFAS No. 162 has been superseded by SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (the Codification) released July 1, 2009.The Codification became the exclusive authoritative reference for non-governmental U.S. GAAP for use in financial statements issued for interim and annual periods ending after September 15, 2009, except for Securities and Exchange Commission (SEC) rules and interpretive releases, which are also authoritative GAAP for SEC registrants. The change establishes non-governmental U.S. GAAP into the authoritative Codification and guidance that is non-authoritative. The contents of the Codification carry the same level of authority, eliminating the four-level GAAP hierarchy previously set forth in Statement 162. The Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in the Codification has become non-authoritative. The Company has revised all GAAP references to reflect the Codification for the quarter ending September 30, 2009.
FASB ASC 260-10-45-60 was issued in June 2008 and requires unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents to be treated as participating securities as defined in FASB ASC 260-10-20 and, therefore, included in the earnings allocation in computing earnings per share under the two-class method described in FASB ASC 260. FASB ASC 260-10-45-60 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. The Company adopted FASB ASC 260-10-45-60 effective January 1, 2009 and adjusted all prior reporting periods to conform to the requirements.
In June 2009 FASB ASC 810-10-05-8 was issued. It requires reporting entities to evaluate former Qualifying Special Purpose Entities or QSPEs for consolidation, changes the approach to determining a variable interest entity’s (VIE) primary beneficiary from a quantitative assessment to a qualitative assessment designed to identify a controlling financial interest, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the characteristics that identify a VIE. This statement requires additional year-end and interim disclosures for public and nonpublic companies that are similar to the disclosures required by FASB ASC 860-10-65-2. The statement is effective for fiscal years beginning after November 15, 2009 and for subsequent interim and annual reporting periods. The Company does not expect this statement to have a significant impact to its financial statements.
FASB ASC 855 was issued June 2009 and is effective for interim or annual financial periods ending after June 15, 2009 and addresses accounting and disclosure requirements related to subsequent events. The statement requires management to evaluate subsequent events through the date the financial statements are issued. Companies are required to disclose the date through which subsequent events have been evaluated. The Company has taken this statement into consideration in Note 14.
FASB ASC 825-10-65-1 requires publicly traded companies to disclose the fair value of financial instruments within the scope of FASB ASC 825 in interim financial statements, adding to the current requirement to make those disclosures in annual financial statements. FASB ASC 825-10-65-1 is effective for interim and annual periods ending after June 15, 2009. The Company has added the required footnote disclosure in Note 10.
(2) Assets Held for Disposition
During 2009, the Partnership has sold certain non-strategic assets and used the proceeds from such sales to reduce long-term indebtedness.
The Partnership sold the Arkoma system in the first quarter of 2009 to an unrelated third party for approximately $10.7 million. The asset had been impaired by $2.6 million in December 2008 to its fair value in anticipation of a first quarter disposition. The related loss on the sale recorded during the nine months ended September 30, 2009 was $0.3 million.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
In addition to the sale of the Arkoma system, the Partnership entered into an agreement in May 2009 to sell its Midstream assets in Alabama, Mississippi and south Texas for $220.0 million reduced by purchase price adjustments provided for in the purchase agreement. Sales proceeds, net of transaction costs and other obligations associated with the sale, of $212.0 million were used to repay long-term indebtedness. The sale closed on August 6, 2009 and the Partnership recognized a gain of $97.4 million.
On August 31, 2009, the Partnership entered into an agreement to sell its natural gas treating business for $266.0 million, including working capital, and subject to certain closing adjustments.
On October 1, 2009, the sale of the Treating assets was finalized and the Partnership will recognize a gain of approximately $85.0 million. In accordance with FASB ASC 360-10-05-4, the consolidated balance sheet at September 30, 2009 reflects the assets and liabilities as held for sale. The assets and liabilities consisted of the following as of September 30, 2009 (in thousands):
         
Current assets
  $ 9,903  
Property and equipment
    148,414  
Intangible assets
    5,538  
Goodwill
    19,673  
Current liabilities
    (6,609 )
Obligations under capital lease
    (2,810 )
 
     
Total net assets held for sale
  $ 174,109  
 
     
The revenues, operating expenses, general and administrative expenses associated directly with the assets held for sale, depreciation and amortization expense, income tax and an allocated interest expense related to the operations of the assets held for sale have been segregated from continuing operations and reported as discontinued operations for all periods. In August 2009, the Partnership expensed $2.0 million of unamortized debt issuance costs associated with the bank credit facility and the senior secured notes. This additional write-off of debt issue costs was directly related to the repayments of $143.0 million on the credit facility and $69.0 million on senior secured notes, from proceeds of the Alabama, Mississippi and south Texas assets disposition. In addition, the Partnership incurred make-whole interest and call premiums of $2.4 million in August 2009 to the holders of the senior secured notes due to the August repayment. These additional interest costs are included in discontinued operations for the three and nine months ended September 30, 2009. No corporate office general and administrative expenses have been allocated to income from discontinued operations. Following are revenues and income from discontinued operations (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
 
Midstream revenues
  $ 54,386     $ 455,891     $ 368,111     $ 1,437,562  
Treating revenues (1)
  $ 13,917     $ 21,678     $ 45,663     $ 56,010  
Income (loss) from discontinued operations, net of tax (1)(2)
  $ (3,361 )   $ 5,302     $ 3,812     $ 18,541  
Gain from sale of discontinued operations, net of tax
  $ 84,827           $ 84,827        
Tax provision on discontinued operations (1)
  $ (11,995 )   $ (1,030 )   $ (13,162 )   $ (3,548 )
Non-controlling interest share of net income (loss) from discontinued operations (1)
  $ (2,342 )   $ 3,842     $ 2,851     $ 13,319  
Non-controlling interest share of gain on sale of discontinued operations
  $ 63,445           $ 63,445        
     
(1)   2008 values include the Seminole Processing Plant sold in November 2008.
 
(2)   See Note 6 for earnings per share calculations.
(3) Long-Term Debt
As of September 30, 2009 and December 31, 2008, long-term debt consisted of the following (in thousands):
                 
    September 30,     December 31,  
    2009     2008  
Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at September 30, 2009 and December 31, 2008 were 6.75% and 3.9%, respectively
  $ 676,493     $ 784,000  
Senior secured notes (including PIK notes as defined below of $5.5 million), weighted average interest rate at September 30, 2009 and December 31, 2008 were 10.5% and 8.0%, respectively
    409,189       479,706  
 
           
 
    1,085,682       1,263,706  
Less current portion
    (21,279 )     (9,412 )
 
           
Debt classified as long-term
  $ 1,064,403     $ 1,254,294  
 
           
On October 1, 2009 proceeds from the disposition of the Treating assets as discussed in Note 2 were used to prepay $173.3 million of bank borrowings and $84.8 million of senior secured note borrowings.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
Credit Facility. As of September 30, 2009, the Partnership had a bank credit facility with a borrowing capacity of $1.036 billion that matures in June 2011. As of September 30, 2009, $818.9 million was outstanding under the bank credit facility, including $142.4 million of letters of credit, leaving approximately $216.6 million available for future borrowing. The Partnership’s borrowing capacity was reduced to $862.2 million on October 1, 2009 due to the $173.3 million prepayment from proceeds of the Treating assets disposition but the amount available for future borrowing of $216.6 million was unchanged.
Obligations under the bank credit facility are secured by first priority liens on all of the Partnership’s 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 rank pari passu in right of payment with the senior secured notes. The bank credit facility is guaranteed by certain of its material subsidiaries. The Partnership may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.
On February 27, 2009, the Partnership entered into the Sixth Amendment to the Fourth Amended and Restated Credit Agreement and Consent (the “Sixth Amendment”) to its credit facility with the bank lending group. Under the Sixth Amendment, borrowings bear interest at the Partnership’s option at the administrative agent’s reference rate plus an applicable margin or London Interbank Offering Rate (LIBOR) plus an applicable margin. The applicable margins for the Partnership’s interest rate and letter of credit fees vary quarterly based on the Partnership’s leverage ratio as defined by the credit facility (the “Leverage Ratio” being generally computed as total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:
                                 
    Bank             Letter        
    Reference     LIBOR     of        
    Rate     Rate     Credit     Commitment  
Leverage Ratio   Advances(a)     Advances(b)     Fees(c)     Fees(d)  
Greater than or equal to 5.00 to 1.00
    3.00 %     4.00 %     4.00 %     0.50 %
Greater than or equal to 4.25 to 1.00 and less than 5.00 to 1.00
    2.50 %     3.50 %     3.50 %     0.50 %
Greater than or equal to 3.75 to 1.00 and less than 4.25 to 1.00
    2.25 %     3.25 %     3.25 %     0.50 %
Less than 3.75 to 1.00
    1.75 %     2.75 %     2.75 %     0.50 %
     
(a)   The applicable margins for the bank reference rate advances ranged from 0% to 0.25% under the bank credit facility prior to the Fifth and Sixth Amendments.
 
(b)   The applicable margins for the LIBOR rate advances ranged from 1.00% to 1.75% under the bank credit facility prior to the Fifth and Sixth Amendments.
 
(c)   The letter of credit fees ranged from 1.00% to 1.75% per annum plus a fronting fee of 0.125% per annum under the bank credit facility prior to the Fifth and Sixth Amendments.
 
(d)   The commitment fees ranged from 0.20% to 0.375% per annum on the unused amount of the credit facility under the bank credit facility prior to the Fifth and Sixth Amendments.
The Sixth Amendment also set a floor for the LIBOR interest rate of 2.75% per annum. The Partnership’s applicable margins for its interest rate and letter of credit (LC) fees during the nine months ended September 30, 2009 have been at the high end of these ranges and, based on the Partnership’s forecasted leverage ratios for the last quarter of 2009, it expects the applicable margins to be at the high end of these ranges for interest rate and LC fees.
The Partnership would have been required to pay a leverage fee under the Sixth Amendment if it did not prepay debt and permanently reduce the banks’ commitments and senior secured note borrowings by the cumulative amounts of $100.0 million on September 30, 2009, $200.0 million on December 31, 2009 and $300.0 million on March 31, 2010. The disposition of Alabama, Mississippi and south Texas assets that closed on August 6, 2009 satisfied the September 30, 2009 and December 31, 2009 de-leveraging targets, and the disposition of Treating assets that closed on October 1, 2009, satisfied the March 31, 2010 de-leveraging target.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
Under the Sixth Amendment, the maximum Leverage Ratio (measured quarterly on a rolling four-quarter basis) is as follows:
    8.25 to 1.00 for the fiscal quarter ending September 30, 2009;
 
    8.50 to 1.00 for the fiscal quarter ending December 31, 2009;
 
    8.00 to 1.00 for the fiscal quarter ending March 31, 2010;
 
    6.65 to 1.00 for the fiscal quarter ending June 30, 2010;
 
    5.25 to 1.00 for the fiscal quarter ending September 30, 2010;
 
    5.00 to 1.00 for the fiscal quarter ending December 31, 2010;
 
    4.50 to 1.00 for any fiscal quarter ending March 31, 2011 through March 31, 2012; and
 
    4.25 to 1.00 for any fiscal quarter ending June 30, 2012 and thereafter.
The minimum cash interest coverage ratio (as defined in the agreement, measured quarterly on a rolling four-quarter basis) is as follows under the Sixth Amendment:
    1.30 to 1.00 for the fiscal quarter ending September 30, 2009;
 
    1.15 to 1.00 for the fiscal quarter ending December 31, 2009;
 
    1.25 to 1.00 for the fiscal quarter ending March 31, 2010;
 
    1.50 to 1.00 for the fiscal quarter ending June 30, 2010;
 
    1.75 to 1.00 for any fiscal quarter ending September 30, 2010 and December 31, 2010; and
 
    2.50 to 1.00 for any fiscal quarter ending March 31, 2011, and thereafter.
Under the Sixth Amendment, no quarterly distributions may be paid to unitholders of the Partnership unless the PIK notes (as defined below) have been repaid and the Leverage Ratio is less than 4.25 to 1.00. If the Leverage Ratio is between 4.00 to 1.00 and 4.25 to 1.00, the Partnership may make quarterly distributions of up to $0.25 per unit if the PIK notes have been repaid. If the Leverage Ratio is less than 4.00 to 1.00, the Partnership may make quarterly distributions to unitholders from available cash as provided by the partnership agreement if the PIK notes have been repaid. The PIK notes are due six months after the earlier of the refinancing or maturity of its bank credit facility. Based on the Partnership’s forecasted leverage ratios for 2009 and the Partnership’s near term ability to refinance its bank credit facility, it does not anticipate making quarterly distributions during 2009 other than the distribution paid in February 2009 related to fourth quarter 2008 operating results. The Partnership will not be able to make distributions to its unitholders in future periods if the leverage ratio does not improve.
The Sixth Amendment also limits the Partnership’s annual capital expenditures (excluding maintenance capital expenditures) to $120.0 million in 2009 and $75.0 million in 2010 and each year thereafter (with unused amounts in any year being carried forward to the next year).
The Sixth Amendment also revised the terms for mandatory repayment of outstanding indebtedness from asset sales and proceeds from incurrence of unsecured debt and equity issuances. Proceeds from debt issuances and from equity issuances not required to prepay indebtedness are considered to be “Excess Proceeds” under the amended bank credit agreement. The Partnership may retain all Excess Proceeds and the Partnership may only make acquisitions using Excess Proceeds. Net proceeds from asset dispositions are required for prepayment at 100% regardless of the leverage ratio. The following table sets forth the amended prepayment terms:
                 
    % of Net Proceeds     % of Net Proceeds  
    from Debt     from Equity  
    Issuances Required     Issuance Required  
Leverage Ratio*   for Prepayment     for Prepayment  
 
               
Greater than or equal to 4.50
    100 %     50 %
Greater or equal to 3.50 and less than 4.50
    50 %     25 %
Less than 3.50
    0 %     0 %
 
     
*   The Leverage Ratio is to be adjusted to give effect to proceeds from debt or equity issuance and the use of such proceeds for each proportional level of Leverage Ratio.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
The prepayments are to be applied pro rata based on total debt (including letter of credit obligations) outstanding under the bank credit agreement and the total debt outstanding under the note agreements described below. Any prepayments of advances on the bank credit facility from proceeds from asset sales, debt or equity issuances will permanently reduce the borrowing capacity or commitment under the facility in an amount equal to 100% of the amount of the prepayment. Any such commitment reduction will not reduce the banks’ $300.0 million commitment to issue letters of credit.
In addition, the bank credit facility contains various covenants that, among other restrictions, limit the Partnership’s ability to:
    incur indebtedness;
 
    grant or assume liens;
 
    make certain investments;
 
    sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions;
 
    change the nature of its business;
 
    enter into certain commodity contracts;
 
    make certain amendments to its or the operating partnership’s partnership agreement; and
 
    engage in transactions with affiliates.
Each of the following will be an event of default under the bank credit facility:
    failure to pay any principal, interest, fees, expenses or other amounts when due;
 
    failure to observe any agreement, obligation, or covenant in the credit agreement, subject to cure periods for certain failures;
 
    certain judgments against the Partnership or any of its subsidiaries, in excess of certain allowances;
 
    certain ERISA events involving the Partnership or its subsidiaries;
 
    bankruptcy or other insolvency events;
 
    a change in control (as defined in the credit agreement); and
 
    the failure of any representation or warranty to be materially true and correct when made.
If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness under the Partnership’s bank credit facility will immediately become due and payable. If any other event of default exists under the bank credit facility, the lenders may accelerate the maturity of the outstanding obligations under the bank credit facility and exercise other rights and remedies.
The Partnership is subject to interest rate risk on the Partnership’s credit facility and has entered into interest rate swaps to reduce this risk. See Note 8 to the financial statements for a discussion of interest rate swaps.
Senior Secured Notes. On February 27, 2009, the Partnership amended its senior note agreement to (i) increase the maximum permitted leverage ratio and to lower the minimum interest coverage ratio it must maintain consistent with the ratios under the Sixth Amendment to the bank credit facility, (ii) revise the mandatory prepayment terms consistent with the terms under the Sixth Amendment to the bank credit facility, (iii) increase the interest rate it pays on the senior secured notes and (iv) provide for the payment of a leverage fee consistent with the terms of the bank credit facility.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
Under the amended senior notes agreement, the senior secured notes will accrue additional interest of 1.25% per annum (the “PIK notes”) in the form of an increase in the principal amount unless the Partnership’s leverage ratio is less than 4.25 to 1.00 as of the end of any fiscal quarter. All PIK notes will be payable six months after the maturity of the bank credit facility, which is currently scheduled to mature in June 2011, or six months after refinancing of such indebtedness if prior to the maturity date.
Per the terms of the amended senior notes agreement the interest rate payable in cash on its senior secured notes will increase by 1.25% per annum for any quarter if its leverage ratio as of the most recently ended fiscal quarter was greater than or equal to 4.25 to 1.00. In addition, commencing on June 30, 2012, the interest rate payable in cash on the Partnership’s senior secured notes will increase by 0.50% per annum for any quarter if its leverage as of the most recently ended fiscal quarter was greater than or equal to 4.00 to 1.00, but this incremental interest will not accrue if the Partnership is paying the incremental 1.25% per annum of interest described in the preceding sentence.
The Partnership recognized a $4.7 million loss on extinguishment of debt during the nine months ended September 30, 2009 due to the February 2009 amendment to the senior secured note agreement. The modifications to this agreement pursuant to this amendment were substantive as defined in FASB ASC 470-50 and were accounted for as the extinguishment of the old debt and the creation of new debt. As a result, the unamortized costs associated with the senior secured notes prior to the amendment as well as the fees paid to the senior secured noteholders for the February 2009 amendment were expensed during the nine months ended September 30, 2009.
These notes represent the Partnership’s senior secured obligations and rank pari passu in right of payment with the bank credit facility. The notes are secured, on an equal and ratable basis with the Partnership’s obligations under the credit facility, by first priority liens on all of its material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all its equity interests in substantially all of the Partnership’s subsidiaries. The senior secured notes are guaranteed by the Partnership’s material subsidiaries.
The senior secured notes issued in 2003 are redeemable, at the Partnership’s option and subject to certain notice requirements, at a purchase price equal to 100.0% of the principal amount together with accrued interest, plus a make-whole amount determined in accordance with the senior secured note agreement. The senior secured notes issued in 2004, 2005 and 2006 provide for a call premium of 103.5% of par beginning three years after issuance at rates declining from 103.5% to 100.0%. The Partnership incurred make-whole interest and call premiums of $2.4 million in August 2009 as a result of the payment of $69.0 million proceeds from the Alabama, Mississippi and south Texas assets disposition.
If an event of default resulting from bankruptcy or other insolvency events occurs, the senior secured notes will become immediately due and payable. If any other event of default occurs and is continuing, holders of at least 50.1% in principal amount of the outstanding notes may at any time declare all the notes then outstanding to be immediately due and payable. If an event of default relating to the nonpayment of principal, make-whole amounts or interest occurs, any holder of outstanding notes affected by such event of default may declare all the notes held by such holder to be immediately due and payable. The senior secured note agreement relating to the notes contains substantially the same covenants and events of default as the Partnership’s bank credit facility.
The Partnership was in compliance with all debt covenants as of September 30, 2009 and expects to be in compliance with debt covenants for the next twelve months.
Intercreditor and Collateral Agency Agreement. In connection with the execution of the bank credit facility and the senior secured note agreement, the lenders under the Partnership’s bank credit facility and the purchasers of the senior secured notes have entered into an Intercreditor and Collateral Agency Agreement, which has been acknowledged and agreed to by the Partnership and its subsidiaries. This agreement appointed Bank of America, N.A. to act as collateral agent and authorized Bank of America, N.A. to execute various security documents on behalf of the lenders under the Partnership’s bank credit facility and the purchasers of the Partnership’s senior secured notes. This agreement specifies various rights and obligations of lenders under the bank credit facility, holders of the senior secured notes and the other parties thereto in respect of the collateral securing the Partnership’s obligations under its bank credit facility and the senior secured note agreement. On February 27, 2009, the holders of the Partnership’s senior secured notes and a majority of the banks under its bank credit facility entered into an amendment to the Intercreditor and Collateral Agency Agreement, which provides that the PIK notes and certain treasury management obligations will be secured by the collateral for its bank credit facility and the senior secured notes, but only paid with proceeds of collateral after obligations under its bank credit facility and the senior secured notes are paid in full.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
(4) Other Long-Term Liabilities
The Partnership entered into various capital leases for certain equipment. Assets, under capital leases as of September 30, 2009, excluding assets considered discontinued operations, are summarized as follows (in thousands):
         
Equipment
  $ 27,192  
Less: Accumulated amortization
    (3,366 )
 
     
Net assets under capital lease
  $ 23,826  
 
     
The following are the minimum lease payments to be made in the following years indicated for the capital leases in effect as of September 30, 2009 (in thousands):
         
2009
  $ 758  
2010
    3,062  
2011 through 2013 ($3,034 annually)
    9,102  
Thereafter
    15,780  
Less: Interest
    (4,367 )
 
     
Net minimum lease payments under capital lease
    24,335  
Less: Current portion of net minimum lease payments
    (3,008 )
 
     
Long-term portion of net minimum lease payments
  $ 21,327  
 
     
     
(5)   Certain Provisions of the Partnership Agreement
(a) Conversion of Senior Subordinated Series D Units
On March 23, 2007, the Partnership issued an aggregate of 3,875,340 senior subordinated series D units representing limited partner interests of the Partnership in a private offering. These senior subordinated series D units converted into common units representing limited partner interests of the Partnership on March 23, 2009. Since the Partnership did not make distributions of available cash from operating surplus, as defined in the partnership agreement, of at least $0.62 per unit on each outstanding common unit for the quarter ending December 31, 2008, each senior subordinated series D unit converted into 1.05 common units for a total issuance of 4,069,106 common units.
(b) Cash Distributions from the Partnership
Unless restricted by the terms of its credit facility, 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 and subordinated 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 it distributes in excess of $0.3125 per unit and 48.0% of amounts it distributes in excess of $0.375 per unit. No incentive distributions were earned by the Company as general partner for the three and nine months ended September 30, 2009. Incentive distributions totaling $6.7 million and $30.8 million were earned by the Company as general partner for the three and nine months ended September 30, 2008, respectively.
See Note 3 for a description of the Partnership’s credit facilities which restrict the Partnership’s ability to make future distributions.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
(c) Allocation of Partnership Income
Net income for the general partner consists of incentive distributions as described in Note 5(b) above, a deduction for stock-based compensation attributable to CEI’s stock options and restricted shares and 2.0% of the original Partnership’s net income adjusted for the CEI stock-based compensation specifically allocated to the general partner. The remaining net income after incentive distributions and CEI-related stock-based compensation is allocated pro rata between the 2.0% general partner interest and the common units. The following table reflects the Company’s general partner share of the Partnership’s net income (loss) (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Income allocation for incentive distributions
  $     $ 6,674     $     $ 30,772  
Stock-based compensation attributable to CEI’s stock options and restricted shares
    (819 )     (775 )     (2,225 )     (3,383 )
2% general partner interest in net income (loss)
    1,500       (89 )     1,015       472  
 
                       
General partner share of net income
  $ 681     $ 5,810     $ (1,210 )   $ 27,861  
 
                       
The Company also owns limited partner common units in the Partnership. The Company’s share of the Partnership’s net income (loss) attributable to its limited partner common units was a net income of $24.6 million and a net loss of $4.0 million for the three months ended September 30, 2009 and 2008, respectively, and a net income of $16.3 million and a net loss of $2.9 million for the nine months ended September 30, 2009 and 2008, respectively.
(6) Earnings per Share and Anti-Dilutive Computations
Basic earnings per share was computed by dividing net income (loss) by the weighted average number of common shares outstanding for the three and nine months ended September 30, 2009 and 2008. The computation of diluted earnings per share further assumes the dilutive effect of common share options and restricted shares when the Company is in an income position.
FASB ASC 260-10-45-61A was issued in May 2008 with an effective date for fiscal years beginning after December 15, 2008 and interim periods within those years. This FASB ASC requires unvested share-based payments that entitle employees to receive non-forfeitable dividends to also be considered participating securities, as defined in FASB ASC 260-10-20. The Company was impacted by this FASB ASC and has calculated earnings attributable to unvested restricted shares and adjusted earnings per unit calculations for the three and nine months ended September 30, 2009 and the comparative three and nine months ended September 30, 2008 to reflect implementation of the FASB ASC.
The following table reflects the computation of basic earnings per share for the periods presented (in thousands except per share amounts):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Net income attributable to Crosstex Energy, Inc
  $ 15,466     $ 540     $ 3,538     $ 28,698  
 
                       
Distributed earnings allocated to:
                               
Common shares
  $     $ 17,593     $ 4,178     $ 46,278  
Unvested restricted shares
          306       50       692  
 
                       
Total distributed earnings
  $     $ 17,899     $ 4,228     $ 46,970  
 
                       
Undistributed income (loss) allocated to:
                               
Common shares
  $ 15,289     $ (17,064 )   $ (680 )   $ (17,970 )
Unvested restricted shares
    177       (295 )     (10 )     (302 )
 
                       
Total undistributed income (loss)
  $ 15,466     $ (17,359 )   $ (690 )   $ (18,272 )
 
                       
Net income allocated to:
                               
Common shares
  $ 15,289     $ 529     $ 3,498     $ 28,308  
Unvested restricted shares
    177       11       40       390  
 
                       
Total net income
  $ 15,466     $ 540     $ 3,538     $ 28,698  
 
                       
Income from discontinued operations:
                               
Common shares
  $ 20,096     $ 1,437     $ 22,045     $ 5,182  
Unvested restricted shares
    267       24       298       40  
 
                       
Total income from discontinued operations
  $ 20,363     $ 1,461     $ 22,343     $ 5,222  
 
                       
Basic and diluted net income (loss) per share from continuing operations:
                               
Common basic and diluted
  $ (0.10 )   $ (0.02 )   $ (0.40 )   $ 0.50  
 
                       
Basic and diluted net income from discontinued operations:
                               
Common basic and diluted
  $ 0.43     $ 0.03     $ 0.47     $ 0.11  
 
                       
Total basic and diluted net income per share:
                               
Common basic and diluted
  $ 0.33     $ 0.01     $ 0.08     $ 0.61  
 
                       

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
The following are the common share amounts used to compute the basic and diluted earnings per common share for the three and nine months ended September 30, 2009 and 2008 (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Basic earnings per share:
                               
Weighted average common shares outstanding
    46,488       46,299       46,462       46,285  
Diluted earnings per share:
                               
Weighted average common shares outstanding
    46,488       46,299       46,462       46,285  
Dilutive effect of restricted shares
    62       304       53       292  
Dilutive effect of exercise of options outstanding
          46             49  
 
                       
Diluted shares
    46,550       46,649       46,515       46,626  
 
                       
(7) Employee Incentive Plans
(a) Long-Term Incentive Plans
The Company accounts for share-based compensation in accordance with the provisions of 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 share-based payment plans for employees, which are described below. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Cost of share-based compensation charged to general and administrative expense
  $ 1,908     $ 1,385     $ 5,098     $ 6,878  
Cost of share-based compensation charged to operating expense
    471       503       1,239       1,383  
 
                       
Total amount charged to income
  $ 2,379     $ 1,888     $ 6,337     $ 8,261  
 
                       
Interest of non-controlling partners in share-based compensation
  $ 991     $ 681     $ 2,615     $ 2,963  
 
                       
Amount of related income tax benefit recognized in income
  $ 504     $ 447     $ 1,370     $ 1,964  
 
                       
(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 nine months ended September 30, 2009 is provided below:
                 
    Nine Months Ended  
    September 30, 2009  
            Weighted  
            Average  
    Number of     Grant-Date  
Crosstex Energy, L.P. Restricted Units:   Units     Fair Value  
Non-vested, beginning of period
    544,067     $ 31.90  
Granted
    1,219,725       2.40  
Vested*
    (184,940 )     18.59  
Forfeited
    (168,712 )     9.53  
 
           
Non-vested, end of period
    1,410,140     $ 8.46  
 
           
Aggregate intrinsic value, end of period (in thousands)
  $ 7,431          
 
             
 
     
*   Vested units include 52,604 units withheld for payroll taxes paid on behalf of employees.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
The Partnership issued performance-based restricted units in 2007 and 2008 to executive officers. The minimum level of performance-based awards is included in restricted units outstanding and is included in the current share-based compensation cost calculations at September 30, 2009. The achievement of greater than the minimum performance targets in the current business environment is less than probable. All performance-based awards are subject to reevaluation and adjustment until the restricted units vest.
The Partnership awarded 803,632 restricted unit grants during the nine months ended September 30, 2009 to certain of the management team. Half of these units vest one year from the date of grant. The remaining fifty percent of the units are performance-based awards that vest one year from the date of grant if the Partnership achieves certain performance metrics. As of September 30, 2009, the Partnership expects to meet the performance objectives stated in the grant with adjustments deemed necessary due to the disposition of assets in 2009. The performance-based units are shown in the balance of outstanding restricted units and included in the current share-based compensation calculation for the three and nine months ended September 30, 2009.
A summary of the restricted units aggregate intrinsic value (market value at vesting date) and fair value (market value at date of grant) of units vested during the three and nine months ended September 30, 2009 and 2008 are provided below (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
Crosstex Energy, L.P. Restricted Units:   2009     2008     2009     2008  
Aggregate intrinsic value of units vested
  $ 253     $ 303     $ 725     $ 5,515  
Fair value of units vested
  $ 547     $ 463     $ 3,439     $ 5,898  
As of September 30, 2009, there was $4.6 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.3 years.
(c) Partnership Unit Options
The following weighted average assumptions were used for the Black-Scholes option pricing model for grants during the three and nine months ended September 30, 2009 and 2008:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
Crosstex Energy, L.P. Unit Options Granted:   2009     2008     2009     2008  
Weighted average distribution yield
    0 %     7.90 %     0 %     7.15 %
Weighted average expected volatility
    75.0 %     27.0 %     75.0 %     29.98 %
Weighted average risk free interest rate
    2.53 %     2.99 %     2.53 %     1.81 %
Weighted average expected life
  6 years     6 years     6 years     6 years  
Weighted average contractual life
  10 years     10 years     10 years     10 years  
Weighted average fair value of unit options granted
  $ 2.08     $ 2.13     $ 2.08     $ 3.48  
In May 2009, the Partnership’s unitholders approved an amendment to the Partnership’s long-term incentive plan to allow an option exchange program. This option exchange program was offered to all eligible employees excluding executive officers and directors because options held by employees were “underwater,” meaning the exercise price of the options were higher than the current market price of the common units. The terms of the offer included an exchange ratio of 3 old options for 1 replacement option, with an exercise price of $4.80 per common unit (120% of the average closing sales price for five trading days prior to the date of grant) which will vest over 2 years (50% after year 1 and 50% after year 2). In June 2009, a total of 453 employees elected to exchange 1,032,403 old options for 344,319 replacement options pursuant to this option exchange program. There was no incremental compensation cost resulting from the modifications under this option exchange program.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
There were no options exercised during the nine months ended September 30, 2009. A summary of the unit option activity for the nine months ended September 30, 2009 is provided below:
                 
    Nine Months Ended  
    September 30, 2009  
            Weighted  
    Number of     Average  
Crosstex Energy, L.P. Unit Options:   Units     Exercise Price  
Outstanding, beginning of period
    1,304,194     $ 30.64  
Granted
    379,756       3.11  
Issued in exchange
    344,319       4.80  
Rendered in exchange
    (1,032,403 )     31.34  
Forfeited
    (244,045 )     29.05  
Expired
    (24,116 )     28.71  
 
           
Outstanding, end of period
    727,705     $ 6.89  
 
           
Options exercisable at end of period
    124,413     $ 16.42  
Weighted average contractual term (years) end of period:
               
Options outstanding
    8.6          
Options exercisable
    3.6          
Aggregate intrinsic value end of period (in thousands):
               
Options outstanding
  $ 829          
Options exercisable
  $ 26          
A summary of the unit options intrinsic value exercised (market value in excess of exercise price at date of exercise) and fair value of units vested (value per Black-Scholes option pricing model at date of grant) during the three and nine months ended September 30, 2009 and 2008 are provided below (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
Crosstex Energy, L.P., Unit Options:   2009     2008     2009     2008  
Intrinsic value of units options exercised
  $     $ 71     $     $ 742  
Fair value of units vested
  $ 91     $ 77     $ 2,621     $ 265  
As of September 30, 2009, there was $1.1 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 1.3 years.
(d) Crosstex Energy, Inc.’s Stock and Option Plan
The Company’s restricted shares are included in stock based compensation 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 nine months ended September 30, 2009 is provided below:
                 
    Nine Months Ended  
    September 30, 2009  
            Weighted  
    Number of     Average Grant-  
Crosstex Energy, Inc. Restricted Shares:   Shares     Date Fair Value  
Non-vested, beginning of period
    604,313     $ 27.62  
Granted
    406,052       4.13  
Vested*
    (217,899 )     16.70  
Forfeited
    (92,621 )     15.43  
 
           
Non-vested, end of period
    699,845     $ 15.79  
 
           
Aggregate intrinsic value, end of period (in thousands)
  $ 3,695          
 
             
 
     
*   Vested shares include 67,733 shares withheld for payroll taxes paid on behalf of employees.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
The Company issued performance-based restricted shares in 2007 and 2008 to executive officers. The minimum level of performance-based awards is included in restricted shares outstanding and is included in the current share-based compensation cost calculations at September 30, 2009. The achievement of greater than the minimum performance targets in the current business environment is less than probable. All performance-based awards are subject to reevaluation and adjustment until the restricted shares vest.
A summary of the restricted shares’ aggregate intrinsic value (market value at vesting date) and fair value (market value at date of grant) of shares vested during the three and nine months ended September 30, 2009 and 2008 are provided below (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
Crosstex Energy, Inc. Restricted Shares:   2009     2008     2009     2008  
Aggregate intrinsic value of shares vested
  $ 107     $ 606     $ 831     $ 12,979  
Fair value of shares vested
  $ 371     $ 517     $ 3,640     $ 6,390  
As of September 30, 2009, there was $4.4 million of unrecognized compensation costs related to non-vested CEI restricted shares for officers and employees. The cost is expected to be recognized over a weighted average period of 1.4 years.
CEI Stock Options
The following is a summary of the CEI stock options outstanding as of September 30, 2009:
                 
    Nine Months Ended  
    September 30, 2009  
    Number of     Weighted Average  
Crosstex Energy, Inc. Stock Options:   Shares     Exercise Price  
Outstanding, beginning of period
    67,500     $ 9.54  
Options exercisable at end of period
    52,500       8.45  
Weighted average contractual term (years) end of period
    5.2          
Aggregate intrinsic value end of period (in thousands)
  $          
A summary of the stock options intrinsic value exercised (market value in excess of exercise price at date of exercise) and fair value (value per Black-Scholes option pricing model at date of grant) of shares vested during the nine months ended September 30, 2009 is provided below (in thousands):
                 
    Nine Months Ended  
    September 30,  
Crosstex Energy, Inc. Stock Options:   2009     2008  
Intrinsic value of stock options exercised
  $     $ 1,089  
Fair value of shares vested
  $ 28     $ 14  
As of September 30, 2009 there was less than $0.1 million of unrecognized compensation costs related to non-vested CEI stock options. The cost is expected to be recognized over a weighted average period of 0.1 years.
(8) Derivatives
The Partnership manages exposure to interest rate risk and commodity price risk through the use of derivative instruments and hedging activities. FASB ASC 815-10-65-1 was issued in March 2008 requiring additional disclosures on derivative instruments that would provide insight into the reason for the use of derivative instruments, give transparency to the location of derivatives within the financial statements and the financial impact of the derivative activity and provide disclosure about credit risk to provide additional information about liquidity. These disclosure requirements are in addition to those already required under FASB ASC 815. The Partnership has historically presented detailed information about derivative activities, but has updated the current disclosure to provide the requirements of FASB ASC 815-10-65-1.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
Interest Rate Swaps
The Partnership is subject to interest rate risk on its credit facility and has entered into interest rate swaps to reduce this risk.
The Partnership entered into eight interest rate swaps prior to 2008. Each swap fixed the three month LIBOR rate, prior to credit margin, at the indicated rates for the specified amounts of related debt outstanding over the term of each swap agreement. In January 2008, the Partnership amended existing swaps with the counterparties in order to reduce the fixed rates and extend the terms of the existing swaps by one year and entered into one new swap. The table below reflects the swaps as amended:
                             
                        Notional Amounts  
Trade Date   Term   From   To   Rate     (in thousands)  
November 14, 2006
  4 years   November 28, 2006   November 30, 2010     4.3800 %   $ 50,000  
March 13, 2007
  4 years   March 30, 2007   March 31, 2011     4.3950 %     50,000  
July 30, 2007
  4 years   August 30, 2007   August 30, 2011     4.6850 %     100,000  
August 6, 2007
  4 years   August 30, 2007   August 31, 2011     4.6150 %     50,000  
August 9, 2007
  3 years   November 30, 2007   November 30, 2010     4.4350 %     50,000  
August 16, 2007*
  4 years   October 31, 2007   October 31, 2011     4.4875 %     100,000  
September 5, 2007
  4 years   September 28, 2007   September 28, 2011     4.4900 %     50,000  
 
                         
 
                      $ 450,000  
 
                         
 
     
*   Amended swap is a combination of two swaps that each had a notional amount of $50.0 million with the same original term.
The Partnership had previously elected to designate all interest rate swaps (except the November 2006 swap) as cash flow hedges for FASB ASC 815 accounting treatment. Accordingly, unrealized gains and losses relating to the designated interest rate swaps were recorded in accumulated other comprehensive income. Immediately prior to the January 2008 amendments, these swaps were de-designated as cash flow hedges. The unrealized loss in accumulated other comprehensive income of $17.0 million at the de-designation date is being reclassified to earnings over the remaining original terms of the swaps using the effective loss of interest method. The related loss reclassified to earnings and included in other income (expense) in the consolidated statements of operations as part of interest expense is $1.7 million for both the three month periods ended September 30, 2009 and 2008 and $5.1 million and $4.7 million during the nine months ended September 30, 2009 and 2008, respectively.
The Partnership has elected not to designate any of the amended swaps as cash flow hedges for FASB ASC 815 treatment. Accordingly, unrealized gains and losses are recorded through the consolidated statement of operations in other income (expense) as part of interest expense, net, over the period hedged.
In September 2008, the Partnership entered into four additional interest rate swaps. The effect of the new interest rate swaps was to convert the floating rate portion of the original swaps on $450.0 million from three month LIBOR to one month LIBOR. The Partnership received a cash settlement in September 2008 of $1.4 million which represented the present value of the basis point differential between one month LIBOR and three month LIBOR.
The table below aligns the new swap, which receives one month LIBOR and pays three month LIBOR, with the original interest rate swaps.
                     
                Notional Amounts  
Original Swap Trade Date   New Trade Date   From   To   (in thousands)  
March 13, 2007
  September 12, 2008   September 30, 2008   March 31, 2011   $ 50,000  
September 5, 2007
  September 12, 2008   September 30, 2008   September 28, 2011     50,000  
 
                   
August 16, 2007
  September 12, 2008   October 30, 2008   October 31, 2011     100,000  
 
                   
November 14, 2006
  September 12, 2008   November 28, 2008   November 30, 2010     50,000  
August 9, 2007
  September 12, 2008   November 28, 2008   November 30, 2010     50,000  
July 30, 2007
  September 12, 2008   November 28, 2008   August 30, 2011     100,000  
 
                   
August 6, 2007
  September 23, 2008   November 28, 2008   August 30, 2011     50,000  
 
                 
 
              $ 450,000  
 
                 

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
The impact of the interest rate swaps on net income (loss) is included in the consolidated statements of operations as part of interest expense, net, as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Change in fair value of derivatives that do not qualify for hedge accounting
  $ (948 )   $ (3,853 )   $ 2,470     $ 2,210  
Realized losses on derivatives
    (4,914 )     (583 )     (14,130 )     (2,547 )
 
                       
 
  $ (5,862 )   $ (4,436 )   $ (11,660 )   $ (337 )
 
                       
The fair value of derivative assets and liabilities relating to interest rate swaps are as follows (in thousands):
                 
    September 30,     December 31,  
    2009     2008  
Fair value of derivative assets — current
  $     $ 149  
Fair value of derivative liabilities — current
    (18,234 )     (17,217 )
Fair value of derivative liabilities — long-term
    (9,786 )     (18,391 )
 
           
Net fair value of derivatives
  $ (28,020 )   $ (35,459 )
 
           
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 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 Partnership commonly enters into various derivative financial transactions which it does not designate as hedges. These transactions include swing swaps, third party on-system financial swaps, marketing financial swaps, storage swaps, basis swaps, processing margin swaps, and liquid swaps. Swing swaps are generally short-term in nature (one month), and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. 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. Marketing financial swaps are similar to on-system financial swaps, but are entered into for customers not connected to the Partnership’s systems. Storage swaps transactions protect against changes in the value of gas that the Partnership has stored to serve various operational requirements. Basis swaps are used to hedge basis location price risk due to buying gas into one of the Partnership’s systems on one index and selling gas off that same system on a different index. Processing margin financial swaps are used to hedge fractionation spread risk at the Partnership’s processing plants relating to the option to process or to bypass equity gas. Liquids financial swaps are used to hedge price risk on percent of liquids (POL) contracts.
The components of (gain) loss on derivatives in the consolidated statements of operations relating to commodity swaps are as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Change in fair value of derivatives that do not qualify for hedge accounting
  $ (1,126 )   $ 99     $ (662 )   $ (713 )
Realized (gains) losses on derivatives
    29       (3,087 )     (6,311 )     (6,800 )
Ineffective portion of derivatives qualifying for hedge accounting
    (11 )     (152 )     (14 )     (17 )
 
                       
Net gains related to commodity swaps
    (1,108 )     (3,140 )     (6,987 )     (7,530 )
Adjusted for net gains (losses) included in income from discontinued operations
    (564 )     684       264       3,244  
 
                       
Gain on derivatives included in continuing operations
  $ (1,672 )   $ (2,456 )   $ (6,723 )   $ (4,286 )
 
                       

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
The fair value of derivative assets and liabilities relating to commodity swaps excluding net fair value of derivatives liability included in assets held for sale of $1.0 million are as follows (in thousands):
                 
    September 30,     December 31,  
    2009     2008  
 
Fair value of derivative assets — current, designated
  $ 2,094     $ 13,714  
Fair value of derivative assets — current, non-designated
    8,328       13,303  
Fair value of derivative assets — long term, designated
    29        
Fair value of derivative assets — long term, non-designated
    8,672       4,628  
Fair value of derivative liabilities — current, designated
    (314 )      
Fair value of derivative liabilities — current, non-designated
    (6,013 )     (11,289 )
Fair value of derivative liabilities — long term, designated
    (29 )      
Fair value of derivative liabilities — long-term, non-designated
    (8,064 )     (4,384 )
 
           
Net fair value of derivatives
  $ 4,703     $ 15,972  
 
           
Set forth below is the summarized notional volume and fair value of all instruments held for price risk management purposes and related physical offsets at September 30, 2009 (all gas volumes are expressed in MMBtu’s and all liquids volumes are expressed in gallons). The remaining term of the contracts extend no later than December 2010 for derivatives except for certain basis swaps that extend to March 2012. 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.
                 
September 30, 2009  
Transaction Type   Volume     Fair Value  
    (In thousands)  
 
               
Cash Flow Hedges:*
               
Natural gas swaps (short contracts)
    (102 )   $ 335  
Liquids swaps (short contracts)
    (11,212 )     1,442  
Liquids swaps (long contracts)
    1,247       3  
 
             
Total swaps designated as cash flow hedges
          $ 1,780  
 
             
 
               
Mark to Market Derivatives:*
               
Swing swaps (long contracts)
    406     $ (1 )
Physical offsets to swing swap transactions (short contracts)
    (406 )      
Swing swaps (short contracts)
    (3,884 )     (37 )
Physical offsets to swing swap transactions (long contracts)
    3,884        
 
               
Basis swaps (long contracts)
    78,596       11,796  
Physical offsets to basis swap transactions (short contracts)
    (450 )     1,653  
Basis swaps (short contracts)
    (56,730 )     (8,607 )
Physical offsets to basis swap transactions (long contracts)
    761       (1,661 )
 
               
Third-party on-system financial swaps (long contracts)
    339       (992 )
Third-party on-system financial swaps (short contracts)
    (122 )     (43 )
 
               
Processing margin hedges — liquids (short contracts)
    (17,639 )     (679 )
Processing margin hedges — gas (long contracts)
    2,002       649  
 
               
Liquids swaps — non-designated (short contracts)
    (1,233 )     (15 )
 
               
Storage swap transactions (short contracts)
    (360 )     (175 )
 
               
Less: Mark to market derivatives included in assets held for sale
            1,035  
 
             
Total Mark to market derivatives
          $ 2,923  
 
             
 
     
*   All are gas contracts, volume in MMBtu’s, except for processing margin hedges — liquids and all liquids swaps (volume in gallons).

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss of $22.1 million would be reduced to $11.1 million due to the netting feature. If the counterparties failed to completely perform according to the terms of the contracts the maximum loss the Partnership would sustain is $1.6 million with financial institutions and $9.5 million with other energy companies.
Impact of Cash Flow Hedges
The impact of realized gains or losses from derivatives designated as cash flow hedge contracts in the consolidated statements of operations is summarized below (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
Increase (Decrease) in Revenue   2009     2008     2009     2008  
Natural gas
  $ 605     $ (811 )   $ 1,762     $ (691 )
Liquids
    1,155       (3,370 )     8,921       (14,305 )
Adjusted for realized (gain) loss included in income from discontinued operations
    (187 )     1,427       (852 )     3,560  
 
                       
 
  $ 1,573     $ (2,754 )   $ 9,831     $ (11,436 )
 
                       
Natural Gas
As of September 30, 2009, an unrealized derivative fair value gain of $0.3 million related to cash flow hedges of gas price risk was recorded in accumulated other comprehensive income (loss) and is expected to be reclassified into earnings through December 2009. The actual reclassification to earnings will be based on mark to market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.
The settlement of cash flow hedge contracts related to October 2009 gas production increased gas revenue by approximately $0.1 million.
Liquids
As of September 30, 2009, an unrealized derivative fair value gain of $1.4 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). Of this net amount, a $1.4 million gain is expected to be reclassified into earnings through September 2010. The actual reclassification to earnings will be based on mark to market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
Derivatives Other Than Cash Flow Hedges
Assets and liabilities related to third party derivative contracts, swing swaps, basis swaps, storage swaps and processing margin 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 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 to     More Than     Total  
    One Year     Two Years     Two Years     Fair Value  
September 30, 2009
  $ 2,315     $ 561     $ 47     $ 2,923  
     
(9)   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 establishes 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 swaps and interest rate swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. The Partnership determines the value of interest rate swap contracts by utilizing inputs and quotes from the counterparties to these contracts. The reasonableness of these inputs and quotes is verified by comparing similar inputs and quotes from other counterparties as of each date for which financial statements are prepared. The Partnership’s contracts are all level two contracts under FASB ASC 820.
Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in thousands):
         
    Level 2  
 
Interest Rate Swaps*
  $ (28,020 )
Commodity Swaps*
    3,668  
Adjusted for net liability value of commodity swaps included in assets held for sale
    1,035  
 
     
Total
  $ (23,317 )
 
     
 
     
*   Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income (loss) at each measurement date. Accumulated other comprehensive income (loss) also includes the unrealized losses on interest rate swaps of $17.0 million recorded prior to de-designation in January 2008, of which $11.5 million has been amortized to earnings through September 2009.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
     
(10)   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).
                                 
    September 30, 2009     December 31, 2008  
    Carrying     Fair     Carrying     Fair  
    Value     Value     Value     Value  
 
Cash and cash equivalents
  $ 11,410     $ 11,410     $ 13,959     $ 13,959  
Trade accounts receivable and accrued revenues
    165,866       165,866       341,853       341,853  
Fair value of derivative assets
    19,123       19,123       31,794       31,794  
Note receivable
    67       67       375       375  
Accounts payable, drafts payable and accrued gas purchases
    121,465       121,465       315,622       315,622  
Long-term debt
    1,085,682       1,068,590       1,263,706       1,158,351  
Obligations under capital lease
    24,335       23,128       27,896       27,269  
Fair value of derivative liabilities
    42,440       42,440       51,281       51,281  
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 carrying value for the note receivable approximates the fair value because this note earns interest based on the current prime rate.
The Company’s long-term debt was comprised of borrowings under a revolving credit facility totaling $676.5 million and $784.0 million as of September 30, 2009 and December 31, 2008, respectively, which accrues interest under a floating interest rate structure. Accordingly, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of September 30, 2009 and December 31, 2008, the Company also had borrowings totaling $409.2 million and $479.7 million, respectively, under senior secured notes with a weighted average interest rate of 10.5% and 8.0%, respectively. The fair value of these borrowings as of September 30, 2009 and December 31, 2008 were adjusted to reflect current market interest rate for such borrowings as of September 30, 2009 and December 31, 2008, respectively.
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 Company and/or the counterparty as required under FASB ASC 820.
(11) Other Income
The Company recorded $7.8 million in other income during the nine months ended September 30, 2008, primarily from the settlement of disputed liabilities that were assumed with an acquisition.
(12) Income Tax
The Company has recorded a deferred tax asset in the amount of $8.5 million and $3.9 million relating to the difference between its book and tax basis of its investment in the Partnership as of September 30, 2009 and December 31, 2008, respectively. Because the Company can only realize this deferred tax asset upon the liquidation of the Partnership and to the extent of capital gains, the Company has provided a full valuation allowance against this deferred tax asset. The deferred tax asset and the related valuation allowance increased $4.6 million during the first quarter of 2009 due to the conversion of the Partnership’s senior subordinated series D units to common units. The income tax provision for the nine months ended September 30, 2009 reflects a tax benefit of $7.0 million for current period loss from continuing operations offset by the $4.6 million income tax expense attributable to the increase in valuation allowance. Unrecognized tax benefits increased $0.8 million during the nine months ended September 30, 2008, and the increase, if recognized would affect the effective tax rate.
Taxes are shown in the statements of operations as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Income tax provision (benefit)
  $ (2,462 )   $ 1,204     $ (2,406 )   $ 7,743  
Tax provision on discontinued operations
    11,995       1,030       13,162       3,548  
 
                       
Total tax provision (benefit)
  $ 9,533     $ 2,234     $ 10,756     $ 11,291  
 
                       

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — Continued
(13) Commitments and Contingencies
(a) Employment Agreements
Certain members of management of the Company are parties to employment contracts with the general partner of the Partnership. The employment agreements provide those senior managers with severance payments in certain circumstances and prohibit each such person from competing with the general partner of the Partnership or its affiliates for a certain period of time following the termination of such person’s employment.
(b) 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.
In December 2008, Denbury Onshore, LLC (“Denbury”) initiated formal arbitration proceedings against Crosstex CCNG Processing Ltd. (“Crosstex Processing”), Crosstex Energy Services, L.P. (“Crosstex Energy”), Crosstex North Texas Gathering, L.P. (“Crosstex Gathering”) and Crosstex Gulf Coast Marketing, Ltd. (“Crosstex Marketing”), all wholly-owned subsidiaries of the Partnership, asserting a claim for breach of contract under a gas processing agreement. The Crosstex parties filed answers denying Denbury’s allegations and asserting certain counterclaims. Crosstex Energy, Crosstex Marketing, and Crosstex Gathering also asserted that they are improper parties to the arbitration because they are not parties to the gas processing agreement. Denbury amended its pleadings to include a fraudulent inducement claim and seek punitive damages against the Crosstex entities, but has since dropped those claims. The Crosstex entities have withdrawn their counterclaims pursuant to a stipulation among the parties. Denbury’s current claim is for breach of contract damages in the amount of $16.2 million, plus interest and attorney’s fees. A three-person arbitration panel is scheduled to conduct a hearing on the merits commencing December 7, 2009. Although it is not possible to predict with certainty the ultimate outcome of this matter, the Partnership does not believe this will have a material adverse impact on its consolidated results of operations or financial position.
The Partnership (or its subsidiaries) is defending several lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not believe that these claims will have a material adverse impact on its consolidated results of operations or financial condition.
On July 22, 2008, SemStream, L.P. and certain of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. As of July 22, 2008, SemStream, L.P. owed the Partnership approximately $6.2 million, including approximately $3.9 million for June 2008 sales and approximately $2.3 million for July 2008 sales. The Partnership believes the July sales of $2.3 million will receive “administrative claim” status in the bankruptcy proceeding. The debtor’s schedules acknowledge its obligation to Crosstex for an administrative claim in the amount of $2.3 million, but it remains subject to an objection by the lenders’ agent. The Partnership evaluated these receivables for collectibility and provided a valuation allowance of $3.1 million during the year ended December 31, 2008 and $0.8 million during the nine months ended September 30, 2009.
(14) Subsequent Events
The Company evaluated events subsequent to the quarter ending September 30, 2009 through the date of the issuance of the financial statements on November 6, 2009. Events occurring subsequent to September 30, 2009 include the closing of the sale of Treating assets disclosed in Note 2 to the financial statements on October 1, 2009.
Additionally, on October 15, 2009, the Partnership acquired the Eunice NGL processing plant and fractionation facility for $23.5 million in cash and the assumption of $18.1 million in debt. In November 2005, the Partnership acquired the contract rights associated with the Eunice plant as part of the south Louisiana acquisition and has operated and managed the plant under an operating lease with an unaffiliated third party for the past four years. In October 2009, the Partnership acquired the physical plant from the third party lessor under this operating lease.

 

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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report.
Overview
Crosstex Energy, Inc. is a Delaware corporation formed on April 28, 2000 to engage in the gathering, transmission, processing and marketing of natural gas and natural gas liquids (NGLs) through its subsidiaries. On July 12, 2002, we formed Crosstex Energy, L.P., a Delaware limited partnership, to acquire indirectly substantially all of the assets, liabilities and operations of its predecessor, Crosstex Energy Services, Ltd. Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and NGLs. These partnership interests consist of (i) 16,414,830 common units, representing approximately 33.4% of the limited partner interests in Crosstex Energy, L.P., and (ii) 100% ownership interest in Crosstex Energy GP, L.P., 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.
Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. We have no separate operating activities apart from those conducted by the Partnership, and our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. Our consolidated results of operations are derived from the results of operations of the Partnership and also include our gains on the issuance of units in the Partnership, deferred taxes, 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.
Historically the Partnership has operated with two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast, in the north Texas Barnett Shale area, and in Louisiana and Mississippi. In August 2009 the Partnership sold its Alabama, Mississippi and south Texas properties and in October 2009 sold its Treating assets as discussed more fully under “Recent Developments.” The primary focus for continuing operations is on the gathering, processing, transmission and marketing of natural gas and NGLs and providing certain producer services. The Partnership’s geographic focus is in the north Texas Barnett Shale area and in Louisiana. The Partnership manages its operations by focusing on gross margin because its business is generally to purchase and resell natural gas for a margin, or to gather, process, transport and market natural gas or NGLs for a fee. The Partnership buys and sells most of its natural gas at a fixed relationship to the relevant index price so margins for gathering and transmission are not significantly affected by changes in natural gas prices. In addition, the Partnership receives certain fees for processing based on a percentage of the liquids produced and enters into hedge contracts for its expected share of liquids produced to protect margins from changes in liquids prices.
The Partnership’s margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems and processed at its processing facilities and the volumes of NGLs handled at its fractionation facilities. Revenues are generated from four primary sources:
    purchasing and reselling or transporting natural gas on the pipeline systems the Partnership owns;
    processing natural gas at the Partnership’s processing plants and fractionating and marketing the recovered NGLs;
    providing compression services; and
    providing off-system marketing services for producers.
The Partnership generally gathers or transports gas owned by others through its facilities for a fee, or 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. In purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. The Partnership attempts to execute all purchases and sales substantially concurrently, or enters into a future delivery obligation, thereby establishing the basis for the margin the Partnership 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.

 

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The Partnership also realizes gross margins from processing services through three different contract arrangements: processing margins (margins), percentage of liquids (POL) or fee based. Under a margin contract arrangement, the gross margins are higher during periods of high liquid prices relative to natural gas prices. Gross margin results under a POL contract are impacted only by the value of liquids produced. Under fee based contracts margins are driven by throughput volume.
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 volumes moved through the asset.
Recent Developments
During the last half of 2008 global financial markets and economic conditions were disrupted by numerous events that severely constrained liquidity in the capital markets throughout the United States and around the world. Although financial markets and economic conditions have continued to be difficult during 2009, financial markets and economic conditions have been more stable and somewhat improved during the third quarter of 2009.
Conditions in our industry have continued to be challenging in 2009. For example:
    Prices of oil, natural gas and NGLs in 2009 remain below the market price realized throughout most of 2008. Crude oil prices (based on NYMEX futures daily close prices for the prompt month) have improved during 2009 with prices ranging from a low of $33.98 per Bbl in February 12, 2009 to a high of $74.37 per Bbl in August 24, 2009. Weighted average NGL prices (based on the OPIS Mt. Belvieu daily average spot liquids prices) have also improved with prices ranging from a low of $0.58 per gallon in March 16, 2009 to a high of $0.92 per gallon in September 18, 2009. Natural gas prices have declined during 2009 with prices ranging from a high of $6.10 per MMBtu in January 7, 2009 to a low of $1.85 per MMBtu in September 8, 2009. (These prices do not address increases or decreases that may have occurred subsequent to September 30, 2009.)
    Although NGL prices have improved during 2009 together with the related fractionation spreads and POL margin, the Partnerhsip’s processing margins in 2009 have been lower than the processing margins realized in 2008. For the nine months ended September 30, 2009, approximately 32.9% of its gross margin was attributable to gas processing as compared to 48.5% of its gross margin for the nine months ended September 30, 2008.
    The decline in drilling activity by gas producers in the Partnership’s areas of operations that began during the fourth quarter of 2008 as a result of the global economic crisis has continued. Several of its customers, including one of its largest customers in the Barnett Shale, substantially reduced drilling activity during 2009 as compared to their drilling levels during 2008.
    Several offshore production platforms and pipelines that transport gas production to the Partnership’s Pelican, Eunice and Sabine Pass processing plants in south Louisiana were damaged by hurricanes Gustav and Ike, which came ashore in the Gulf Coast in September 2008. Substantially all of the production from the pipeline systems supplying the Pelican, Eunice and Sabine plants has been restored to pre-hurricane levels as of September 30, 2009 but processing volumes at the plants during the nine months ended September 30, 2009 were negatively impacted by lower pipeline system supplies while these pipeline systems were being repaired.
Despite the weaker commodity environment and reduced drilling activity, the Partnership is positioning itself to benefit from a recovering economy. In particular:
    The Partnership has adjusted its business strategy for 2009 to focus on maximizing its liquidity, maintaining a stable asset base, and improving the profitability of its assets by increasing their utilization while controlling costs. The Partnership has also reduced its capital expenditures.
    The Partnership completed the disposition of certain non-strategic assets including the February 2009 sale of the Arkoma system for approximately $10.7 million, the August 2009 sale of its Alabama, Mississippi and south Texas properties for approximately $220.0 million, and the October 2009 sale of its Treating assets for $266.0 million. Substantially all of the proceeds from the August and October 2009 asset sales were used to repay long-term debt.
    The Partnership amended its bank credit facility and its senior secured note agreements in February 2009 to negotiate terms that facilitate its compliance with debt covenants while it operates its assets during the current difficult economic conditions. The terms of the amended agreements allow the Partnership to maintain a higher level of leverage and to maintain a lower interest coverage ratio; however, its interest costs have increased and its ability to pay distributions and incur additional indebtedness has been restricted because the Partnership is operating at higher leverage ratios.

 

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Results of Operations
Set forth in the table below is certain financial and operating data for the periods indicated and excludes financial and operating data considered discontinued operations.
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
    (Dollars in millions)  
 
Midstream revenues
  $ 349.2     $ 854.3     $ 1,049.5     $ 2,650.1  
Purchased gas
    (269.5 )     (775.8 )     (824.8 )     (2,411.0 )
Profit on energy trading activities
    1.5       0.7       3.6       2.3  
 
                       
Total gross margin
  $ 81.2     $ 79.2     $ 228.3     $ 241.4  
 
                       
 
                               
Volumes (MMBtu/d):
                               
Gathering and transportation
    2,038,000       2,073,000       2,069,000       2,030,000  
Processing
    1,257,000       1,499,000       1,183,000       1,805,000  
Producer services
    95,000       80,000       87,000       81,000  
Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008
Gross Margin and Profit on Energy Trading Activities. Gross margin was $81.2 million for the three months ended September 30, 2009 compared to $79.2 million for the three months ended September 30, 2008, an increase of $2.0 million, or 2.6%. The increase was primarily due to higher margins on the Partnership’s gathering and transmission throughput volume. These increases were partially offset by gross margin declines in the processing business due to a less favorable NGL market. Profit on energy trading activities increased for the comparative periods by approximately $0.8 million.
The LIG gathering and transmission system contributed gross margin growth of $4.2 million for the comparative periods primarily due to improved pricing and higher volumes on the northern part of the system offsetting a decrease in sales volume at southern delivery points. Throughput and plant inlet volumes in the north Texas region were relatively unchanged for the three months ended September 30, 2009 over the same period in 2008. However there were moderate gross margin gains in the north Texas region for gathering and transmission systems and processing plants of $1.7 million and $0.5 million, respectively. The weaker processing environment contributed to a significant decline in the gross margins for processing plants in Louisiana for the quarter ended September 30, 2009. Overall the plants in the region reported a margin decrease of approximately $4.8 million. The primary contributors to this decrease were the Eunice, Gibson and Pelican plants which had gross margin declines of $3.5 million, $3.2 million and $1.7 million, respectively. These were offset by a gross margin increase at the Riverside facility of $4.2 million primarily due to a mark to market loss on inventory recorded in the third quarter of 2008. The Arkoma system, which was sold in April 2009, created a negative gross margin variance of $0.7 million when compared to the same period in 2008.
Operating Expenses. Operating expenses were $29.0 million for the three months ended September 30, 2009 compared to $34.4 million for the three months ended September 30, 2008, a decrease of $5.4 million, or 15.6%. The decrease is primarily attributable to the initiatives undertaken in late 2008 and early 2009 to reduce expenses.
General and Administrative Expenses. General and administrative expenses of $16.7 million for the three months ended September 30, 2009 is relatively flat versus the same period in 2008 even though 2009 expense includes a one time charge of $0.9 million for severance costs related to asset sales.
Gain/Loss on Derivatives. The Partnership had a gain on commodity derivatives of $1.7 million for the three months ended September 30, 2009 compared to a gain of $2.5 million for the three months ended September 30, 2008. The derivative transaction types contributing to the net gain are as follows (in millions):
                                 
    Three Months Ended September 30,  
    2009     2008  
(Gain)/Loss on Derivatives:   Total     Realized     Total     Realized  
Basis swaps
  $ (1.8 )   $ (0.7 )   $ (1.4 )   $ (2.7 )
Processing margin hedges
    0.5       0.8       (1.0 )      
Other
    0.2       (0.1 )     (0.7 )     (0.5 )
 
                       
 
    (1.1 )           (3.1 )     (3.2 )
Adjusted for derivative gains (losses) related to assets held for sale and included in income from discontinued operations
    (0.5 )           0.6       1.8  
 
                       
Gain on Derivatives
  $ (1.6 )   $     $ (2.5 )   $ (1.4 )
 
                       

 

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Depreciation and Amortization. Depreciation and amortization expenses were $31.2 million for the three months ended September 30, 2009 compared to $26.9 million for the three months ended September 30, 2008, an increase of $4.3 million, or 15.8%. The increase is primarily attributable to the north Texas expansion and north LIG expansion.
Interest Expense. Interest expense was $26.6 million for the three months ended September 30, 2009 compared to $14.2 million for the three months ended September 30, 2008, an increase of $12.3 million. Interest expense increased by $9.2 million on the senior notes (including PIK interest) and the credit facility due to an increase in interest rates from the February 2009 amendments to the debt agreements. Additionally the interest rate derivatives activity yielded an increase of $1.5 million in expense due to the decrease in LIBOR rates. Net interest expense consists of the following (in millions):
                 
    Three Months Ended  
    September 30,  
    2009     2008  
Senior notes
  $ 7.7     $ 5.5  
Credit facility
    9.2       3.8  
PIK Notes
    1.6        
Mark to market interest rate swaps
    1.0       3.8  
Realized interest rate swap losses
    4.9       0.6  
Capitalized interest
    (0.1 )     (0.5 )
Interest income
    (0.1 )     (0.1 )
Amortization of debt issue cost
    2.0       0.7  
Other
    0.4       0.4  
 
           
Total
  $ 26.6     $ 14.2  
 
           
Income Taxes. An income tax benefit of $2.5 million was generated for the three months ended September 30, 2009 compared to an income tax expense of $1.2 million for the three months ended September 30, 2008. We had a loss from continuing operations, net of non-controlling interest, for the three months ended September 30, 2009 which resulted in a tax benefit of $2.5 million.
Interest of Non-Controlling Partners in the Partnership’s Net Income(Loss) from Continuing Operations. The interest of non-controlling partners in the Partnership’s net loss increased by $1.4 million to a loss of $12.2 million for the three months ended September 30, 2009 compared to a loss of $10.8 million for the three months ended September 30, 2009 due to the changes shown in the following summary (in millions):
                 
    For the Three Months  
    Ended September 30,  
    2009     2008  
Net loss for the Partnership from continuing operations
  $ (19.3 )   $ (11.4 )
(Income) allocation to CEI for the general partner incentive distributions
          (6.7 )
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors
    0.8       0.8  
Loss allocation to CEI for its 2% general partner share of Partnership (income) loss
    0.4       0.2  
 
           
Net loss from continuing operations allocable to limited partners
    (18.1 )     (17.1 )
Less: CEI’s share of net (income) loss allocable to limited partners
    5.9       6.3  
 
           
Non-controlling partners’ share of Partnership net loss from continuing operations
  $ (12.2 )   $ (10.8 )
 
           

 

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Discontinued Operations. The Partnership sold the following non-strategic assets over the past year and used the proceeds from such sales to repay long-term indebtness:
         
Assets   Date of Sale  
12.4% interest in the Seminole Gas Processing Plant
  November 2008
Arkoma assets
  January 2009
Alabama, Mississippi and south Texas assets
  August 2009
Treating Division assets
  October 2009
In accordance with FASB ASC 360-10-05-4, the assets and liabilities and the results of operations related to each of the assets listed above (except the Arkoma assets which were immaterial to the financial statement presentations) were segregated to assets and liabilities held for sale and are presented in income from discontinued operations for the comparative periods in the statements of operations. Revenues, operating expenses, general and administrative expenses associated directly to the assets held for sale, depreciation and amortization, income tax and allocated interest are reflected in the income from discontinued operations. In August 2009, the Partnership expensed $2.0 million of unamortized debt issuance costs associated with the bank credit facility and the senior secured notes due to the repayments of $143.0 million and $69.0 million, respectively, in borrowings from proceeds of the Alabama, Mississippi and south Texas assets disposition. In addition, the Partnership incurred make-whole interest and call premiums of $2.4 million in August 2009 to the holders of the senior secured notes due to the call premium on the August repayment. These additional interest costs are included in discontinued operations for the three months ended September 30, 2009. No corporate office general and administrative expenses have been allocated to income from discontinued operations. Following are the components of revenues and earnings from discontinued operations and operating data (dollars in millions):
                 
    Three Months Ended  
    September 30,  
    2009     2008  
Midstream revenues
  $ 54.4     $ 455.9  
Treating revenues
  $ 13.9     $ 21.7  
Income (loss) from discontinued operations, net of tax
  $ (3.4 )   $ 5.3  
Gain from sale of discontinued operations, net of tax (1)
  $ 84.8        
Gathering and Transmission Volumes (MMBtu/d)
    563,000       584,000  
Processing Volumes (MMBtu/d)
    178,000       184,000  
     
(1)   Gain on sale of discontinued operations relate to disposition of Alabama, Mississippi and south Texas.
Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008
Gross Margin and Profit on Energy Trading Activities. Gross margin was $228.3 million for the nine months ended September 30, 2009 compared to $241.4 million for the nine months ended September 30, 2008, a decrease of $13.1 million, or 5.4%. The decrease was primarily due to weakness in the natural gas processing business driven by less favorable NGL markets. These decreases were partially offset by margin improvement on the gathering and transmission assets. Profit on energy trading activities increased for the comparative periods by approximately $1.3 million.
The weaker processing environment contributed to a significant decline in the gross margins for processing plants in Louisiana for the nine months ended September 30, 2009. Overall the plants in the region reported a margin decrease of approximately $29.2 million. The primary contributors to this decrease were the Gibson, Plaquemine and Eunice plants which had gross margin declines of $9.2 million, $8.5 million and $3.6 million, respectively. The Crosstex Pipeline system in east Texas had a gross margin decline of $2.2 million primarily due to a decline in throughput volumes. The Arkoma system, which was sold in February 2009, created a negative gross margin variance of $2.0 million when compared to the same period in 2008. System expansion in the north Texas region contributed $14.9 million of gross margin growth for the nine months ended September 30, 2009 over the same period in 2008. The gathering systems in the region and North Texas Pipeline (NTP) accounted for approximately $16.4 million of gross margin increases. This increase was partially offset by a gross margin decline of $1.5 million on the processing facilities in north Texas. The LIG gathering and transmission system contributed gross margin growth of $3.6 million for the comparative periods primarily due to improved pricing and higher volumes on the northern part of the system offsetting a decrease in sales volume at southern delivery points.
Operating Expenses. Operating expenses were $84.7 million for the nine months ended September 30, 2009 compared to $93.7 million for the nine months ended September 30, 2008, a decrease of $9.0 million, or 9.6%. The decrease is primarily attributable to initiatives undertaken in late 2008 and early 2009 to reduce expenses.
General and Administrative Expenses. General and administrative expenses were $45.6 million for the nine months ended September 30, 2009 compared to $50.1 million for the nine months ended September 30, 2008, a decrease of $4.4 million, or 8.8%. The decrease is a result of strategic initiatives undertaken by the Partnership to reduce expenses and primarily relate to workforce reductions. Severance costs of $0.9 million related to asset sales are included in the 2009 general and administrative expenses.

 

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Gain/Loss on Derivatives. The Partnership had a gain on commodity derivatives of $6.7 million for the nine months ended September 30, 2009 compared to a gain of $4.3 million for the nine months ended September 30, 2008. The derivative transaction types contributing to the net gain are as follows (in millions):
                                 
    Nine Months Ended September 30,  
    2009     2008  
(Gain)/Loss on Derivatives:   Total     Realized     Total     Realized  
Basis swaps
  $ (3.6 )   $ (1.7 )   $ (6.1 )   $ (6.3 )
Processing margin hedges
    (3.2 )     (3.2 )     (0.8 )     0.2  
Other
    (0.2 )     (1.4 )     (0.6 )     (0.6 )
 
                       
 
    (7.0 )     (6.3 )     (7.5 )     (6.7 )
Adjusted for derivative gains related to assets held for sale and included in income from discontinued operations
    0.3       0.5       3.2       3.0  
 
                       
Gain on Derivatives
  $ (6.7 )   $ (5.8 )   $ (4.3 )   $ (3.7 )
 
                       
Depreciation and Amortization. Depreciation and amortization expenses were $90.9 million for the nine months ended September 30, 2009 compared to $79.3 million for the nine months ended September 30, 2008, an increase of $11.6 million, or 14.6%. The increase is primarily attributable to the north Texas expansion and north LIG expansion.
Interest Expense. Interest expense was $64.8 million for the nine months ended September 30, 2009 compared to $32.8 million for the nine months ended September 30, 2008, an increase of $32.1 million. Interest expense increased by $14.5 million on the senior notes (including PIK interest) and the credit facility due to an increase in interest rates from the February 2009 amendments to the debt agreements. Additionally the interest rate derivatives yielded an increase of $11.8 million in realized expense due to the decrease in LIBOR rates. Net interest expense consists of the following (in millions):
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Senior notes
  $ 20.9     $ 16.6  
PIK notes
    3.6        
Credit facility
    21.8       15.2  
Capitalized interest
    (1.0 )     (2.2 )
Mark to market interest rate swaps
    (2.4 )     (2.2 )
Realized interest rate swap losses
    14.1       2.3  
Interest income
    (0.1 )     (0.3 )
Amortization of debt issue cost
    5.6       2.1  
Other
    2.3       1.3  
 
           
Total
  $ 64.8     $ 32.8  
 
           
Income Taxes. Income tax benefit was $2.4 million for the nine months ended September 30, 2009 compared to an income tax expense of $7.7 million for the nine months ended September 30, 2008. We had a loss from continuing operations, net of non-controlling interest, for the nine months ended September 30, 2009 which resulted in a tax benefit of $7.0 million that was partially offset by an increase in tax expense of $4.6 million attributable to the conversion of the Partnership’s senior subordinated series D units into common units in March 2009. The income tax provision for the nine months ended September 30, 2008 also includes $5.2 million expense related to the issuance of Partnership common units.
Loss on Extinguishment of Debt. We recognized a loss on extinguishment of debt during the nine months ended September 30, 2009 of $4.7 million due to the February 2009 amendment to the senior secured notes agreement. The modifications to this agreement pursuant to this amendment were substantive as defined in FASB ASC 470-50 and were accounted for as the extinguishment of the old debt and the creation of new debt. As a result, the unamortized costs associated with the senior secured notes prior to the amendment as well as the fees paid to the senior secured lenders for the February 2009 amendment were expensed during the nine months ended September 30, 2009.
Other Income. The Partnership recorded $7.8 million in other income during the nine months ended September 30, 2008, primarily from the settlement of disputed liabilities that were assumed with an acquisition.
Gain on Issuance of Units of the Partnership. As a result of the Partnership issuing common units in April 2008 to unrelated parties at a price per unit greater than our equivalent carrying value, our share of net assets of the Partnership increased by $14.7 million and we recognized a gain on issuance of such units during the nine months ended September 30, 2008.

 

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Interest of Non-Controlling Partners in the Partnership’s Net Income (Loss) from Continuing Operations. The interest of non-controlling partners in the Partnership’s net loss increased by $15.1 million to a loss of $32.9 million for the nine months ended September 30, 2009 compared to a loss of $17.8 million for the nine months ended September 30, 2008 due to the changes shown in the following summary (in millions):
                 
    For the Nine Months Ended  
    September 30,  
    2009     2008  
Net loss for the Partnership from continuing operations
  $ (53.3 )   $ (1.3 )
(Income) allocation to CEI for the general partner incentive distributions
          (30.8 )
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors
    2.2       3.4  
(Income)/loss allocation to CEI for its 2.0% general partner share of Partnership (income) loss
    1.0        
 
           
Net income (loss) from continuing operations allocable to limited partners
    (50.1 )     (28.7 )
Less: CEI’s share of net loss allocable to limited partners
    17.2       10.7  
Plus: Non-controlling partners’ share of net income in Denton County Joint Venture
          0.2  
 
           
Non-controlling partners’ share of Partnership net loss from continuing operations
  $ (32.9 )   $ (17.8 )
 
           
Discontinued Operations. The Partnership sold the following non-strategic assets over the past year and used the proceeds from such sales to repay long-term indebtness:
     
Assets   Date of Sale
12.4% interest in the Seminole Gas Processing Plant
  November 2008
Arkoma assets
  January 2009
Alabama, Mississippi and south Texas assets
  August 2009
Treating Division assets
  October 2009
In accordance with FASB ASC 360-10-05-4, the assets and liabilities and the results of operations related to each of the assets listed above (except the Arkoma assets which were immaterial to the financial statement presentations) were segregated to assets and liabilities held for sale and are presented in income from discontinued operations for the comparative periods in the statements of operations. Revenues, operating expenses, general and administrative expenses associated directly to the assets held for sale, depreciation and amortization, income tax and allocated interest are reflected in the income from discontinued operations. In August 2009, the Partnership expensed $2.0 million of unamortized debt issuance costs associated with the bank credit facility and the senior secured notes due to the repayments of $143.0 million and $69.0 million, respectively, in borrowings from proceeds of the Alabama, Mississippi and south Texas assets disposition. In addition, the Partnership incurred make-whole interest and call premiums of $2.4 million in August 2009 to the holders of the senior secured notes due to the call premium on the August repayment. These additional interest costs are included in discontinued operations for the nine months ended September 30, 2009. No corporate office general and administrative expenses have been allocated to income from discontinued operations. Following are the components of revenues and earnings from discontinued operations and operating data (dollars in millions):
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Midstream revenues
  $ 368.1     $ 1,437.6  
Treating revenues
  $ 45.7     $ 56.0  
Income from discontinued operations, net of tax
  $ 3.8     $ 18.5  
Gain from sale of discontinued operations, net of tax (1)
  $ 84.8        
Gathering and Transmission Volumes (MMBtu/d)
    564,000       564,000  
Processing Volumes (MMBtu/d)
    191,000       200,000  
     
(1)   Gain on sale of discontinued operations relate to disposition of Alabama, Mississippi and south Texas.

 

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Critical Accounting Policies
Information regarding the Company’s Critical Accounting Policies is included in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.
Liquidity and Capital Resources
As described in “Overview,” the economic climate has impacted the Partnership’s sources of liquidity during 2009 leading to declines in its cash flows from operating activities and limiting its ability to access debt and equity markets during the past twelve months. As described in each of the sections below, the Partnership has responded to its limited access to capital by reducing its capital expenditures while continuing expansion efforts in its core areas on a more limited basis, by selling non-strategic assets to reduce its long-term indebtedness and by ceasing unit distributions until the Partnership meets certain conditions under its long-term debt agreements. The Partnership will use cash flows from operating activities together with its available borrowing capacity under its bank credit facility to fund its capital expenditures for the next twelve months. The Partnership believes that the steps it has taken over the past year have improved its position to access debt and equity markets in the coming year.
Since our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own, we do not expect to receive any significant cash flows until the Partnership is able to begin making distributions. As of September 30, 2009, we have $10.5 million in cash (excluding cash held by the Partnership) which we expect will be sufficient to pay our expenses and federal income taxes over the next few years based on our forecasted cash flows. We do not anticipate making any future dividend payments until we begin receiving distributions from the Partnership.
Cash Flows from Operating Activities. Net cash provided by operating activities was $61.1 million for the nine months ended September 30, 2009 compared to cash provided by operations of $215.6 million for the nine months ended September 30, 2008. Income before non-cash income and expenses and changes in working capital for comparative periods were as follows (in millions):
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Income before non-cash income and expenses
  $ 70.8     $ 124.0  
Changes in working capital
  $ (9.7 )   $ 91.6  
The primary reason for the decrease in non-cash income and expense of $53.2 million from 2008 to 2009 relates to increased interest expense of $27.8 million, decreased other income of $7.0 million and decreased margin of $17.4 million. Changes in working capital may fluctuate significantly between periods even though the Partnership’s trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles. A large volume of its revenues are collected and a large volume of its gas purchases are paid near each month end or the first few days of the following month so receivable and payable balances at any month end may fluctuate significantly depending on the timing of these receipts and payments. In addition, although the Partnership strives to minimize natural gas and NGLs in inventory, these working inventory balances may fluctuate significantly from period-to-period due to operational reasons and due to changes in natural gas and NGL prices. Working capital also includes mark to market derivative assets and liabilities associated with derivative cash flow hedges which may fluctuate significantly due to the changes in natural gas and NGL prices. The changes in working capital during the nine months ended September 30, 2008 and 2009 are due to the impact of the fluctuations discussed above and are not indicative of any change in operating cash flow trends. At September 30, 2008 the Partnership had cash on hand of $96.9 million due to the timing of payment releases.
Cash Flows from Investing Activities. Net cash provided by investing activities was $164.2 million and net cash used in investing activities was $214.1 million for the nine months ended September 30, 2009 and 2008, respectively. The primary investing outflows were capital expenditures for internal growth, net of accrued amounts, as follows (in millions):
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Growth capital expenditures
  $ 83.6     $ 205.1  
Maintenance capital expenditures
    7.2       12.8  
 
           
Total
  $ 90.8     $ 217.9  
 
           

 

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Net cash invested in Midstream assets was $77.4 million and $178.2 million for the nine months ended September 30, 2009 and 2008, respectively. Net cash invested in Treating assets was $12.2 million for the nine months ended September 30, 2009 and $32.5 million for the nine months ended September 30, 2008. Net cash invested in other corporate assets was $1.2 million for the nine months ended September 30, 2009 and $7.2 million for the nine months ended September 30, 2008.
Cash flows from investing activities for the nine months ended September 30, 2009 and 2008 also includes proceeds from property sales of $245.3 million and $3.8 million, respectively. Proceeds from asset sales for the nine months ending September 30, 2009 consisted primarily of $10.7 million for the Arkoma assets and $214.0 million for the Alabama, Mississippi and south Texas assets. An additional $20.0 million of cash was generated in 2009 by the sale of compressors in north Texas and Louisiana which were leased back through operating leases. The 2008 sales included in continuing operations primarily related to sales of various small Midstream and Treating assets.
Cash Flows from Financing Activities. Net cash used by financing activities was $227.8 million and net cash provided by financing activities was $101.1 million for the nine months ended September 30, 2009 and 2008, respectively. Financing activities during 2009 primarily related to funding of capital expenditures and repayment of long term debt and primarily consisted of borrowings under its bank credit facility, borrowings under capital lease obligations, equity offerings and senior note repayments during 2008 as follows (in millions):
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Net borrowings (payments) under bank credit facility (1)
  $ (107.5 )   $ 118.8  
Senior note repayments (2)
    (76.0 )     (7.1 )
Net borrowings (payments)under capital lease obligations
    (0.4 )     17.6  
Debt refinancing costs
    (13.8 )     (0.4 )
Common unit offerings (3)
          99.9  
 
     
(1)   Includes a $143.0 million payment due to the sale of the Alabama, Mississippi and south Texas assets.
 
(2)   Includes a $69.0 million payment due to sale of the Alabama, Mississippi and south Texas assets.
 
(3)   Net of offering costs.
Dividends to shareholders and distributions to non-controlling partners in the Partnership until recently have been our primary use of cash in financing activities. Total cash distributions made during the nine months ended September 30, 2009 and 2008 were as follows (in millions):
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Dividend to shareholders
  $ 4.2     $ 47.0  
Non-controlling partner distributions
    7.6       47.9  
 
           
Total
  $ 11.8     $ 94.9  
 
           
In order to reduce its interest costs, the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on the Partnership’s revolving credit facility. The Partnership borrows money under its $1.036 billion credit facility to fund checks as they are presented. As of September 30, 2009, the Partnership had approximately $216.6 million of available borrowing capacity under this facility. The Partnership’s borrowing capacity was reduced to $862.2 million on October 1, 2009 due to the $173.3 million prepayment from proceeds of the Treating assets disposition but the amount available for future borrowing of $216.6 million was unchanged. Changes in drafts payable for the nine months ended 2009 and 2008 were as follows (in millions):
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
Decrease in drafts payable
  $ 17.9     $ 28.9  
Working Capital Deficit. We had a working capital deficit of $19.5 million as of September 30, 2009, primarily due to a net liability for our fair value of derivatives of $15.2 million and accounts and drafts payable of $4.2 million as of the same date. Our fair value of derivatives reflects the mark-to-market of such derivatives including a net current liability of $18.2 million related to interest rate swaps and a net current asset of $3.0 million related to commodity derivatives. As discussed under “Cash Flows” above, in order to reduce our interest costs we do not borrow money to fund outstanding checks until they are presented to our bank.

 

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Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2009.
Capital Requirements of the Partnership. The Partnership has reduced its budgeted capital expenditures significantly for 2009 to improve its liquidity. The current economic climate and the Partnership’s leveraged position have limited its ability to secure additional funding for growth and expansion projects. Total capital expenditures in the calendar year 2009 are currently anticipated to be approximately $100.0 million and primarily relate to projects in north Texas and Louisiana pursuant to contractual obligations with producers and vendors. The Partnership will use cash flow from operations and existing capacity under its bank credit facility to fund the reduced capital spending plan during 2009.
During the nine months ended September 30, 2009, its growth capital expenditures, were $83.6 million primarily in north Texas and in north Louisiana. The Partnership continued the expansion of its north Louisiana system during 2009 to provide additional compression thereby increasing capacity by 100 MMcf/d to producers in the Haynesville Shale gas play. This project was completed in July 2009 and the total capacity of the north Louisiana system is approximately 375 MMcf/d. The Partnership has 10 year firm transportation contracts with four major producers subscribing to all of the incremental capacity on this expansion project. The Partnership has contracted additional firm transportation of 35 MMcf/d on the north Louisiana system that is scheduled to come online in November 2009. The Partnership has continued its expansion of its north Texas pipeline gathering system in the Barnett Shale on a limited basis during the nine months ended September 30, 2009 to handle volume growth and to connect new wells to its gathering system pursuant to existing obligations with producers. The Partnership connected and received initial flow from approximately 72 new wells during the nine months ended September 30, 2009.
The Partnership lowered its distribution level to $0.25 per unit for the fourth quarter of 2008 which was paid in February 2009. The amended terms of its credit facility and senior secured note agreement restricts its ability to make distributions unless certain conditions are met. The Partnership does not expect that it will meet these conditions in 2009.
Total Contractual Cash Obligations. A summary of the Partnership’s total contractual cash obligations excluding financial and operating data considered discontinued operations as of September 30, 2009 is as follows (in millions):
                                                         
    Payments Due by Period  
    Total     2009     2010     2011     2012     2013     Thereafter  
Long-term debt
  $ 1,085.7     $ 260.5     $ 17.6     $ 540.7     $ 93.0     $ 83.6     $ 90.3  
Interest payable on fixed long-term debt obligations
    110.7       10.4       29.7       26.9       22.0       13.9       7.8  
PIK interest payable
    19.0                   19.0                    
Capital lease obligations
    28.7       0.8       3.1       3.0       3.0       3.0       15.8  
Operating leases
    55.0       6.2       13.7       9.8       7.5       5.8       12.0  
Unconditional purchase obligations
    2.4       2.4                                
FIN 48 tax obligations
    2.8       2.5       0.1       0.1       0.1              
 
                                         
Total contractual obligations
  $ 1,304.3     $ 282.8     $ 64.2     $ 599.5     $ 125.6     $ 106.3     $ 125.9  
 
                                         
The above table does not include any physical or financial contract purchase commitments for natural gas.
Operating leases as presented in the table above no longer include $39.6 million of lease obligations for the Eunice facility. The Partnership acquired the Eunice NGL processing plant and fractionation facility on October 15, 2009, and will no longer have the lease obligation to an outside third party.
The current maturity of long-term debt includes the October 2009 paydown of $258.1 million due to proceeds from disposition of Treating assets.
The Partnership’s interest payable under its credit facility is not reflected in the above table because such amounts depend on outstanding balances and interest rates which will vary from time to time. Based on balances outstanding and rates in effect at September 30, 2009, annual interest payments would be $45.7 million. The interest amounts also exclude estimates of the effect of the Partnership’s interest rate swap contracts.
The unconditional purchase obligations for 2009 relate to purchase commitments for equipment.

 

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Indebtedness
As of September 30, 2009 and December 31, 2008, long-term debt consisted of the following (in millions):
                 
    September 30,     December 31,  
    2009     2008  
Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at September 30, 2009 and December 31, 2008 were 6.75% and 3.9%, respectively
  $ 676.5     $ 784.0  
Senior secured notes (including PIK notes of $5.5 million), weighted average interest rate at September 30, 2009 and December 31, 2008 were 10.5% and 8.0%, respectively
    409.2       479.7  
 
           
 
    1,085.7       1,263.7  
Less current portion
    (21.3 )     (9.4 )
 
           
Debt classified as long-term
  $ 1,064.4     $ 1,254.3  
 
           
On October 1, 2009, proceeds from the disposition of the Treating assets as discussed in Note 2 were used to prepay $173.3 million of bank borrowings and $84.8 million of senior secured note borrowings.
As of September 30, 2009, the Partnership had a bank credit facility with a borrowing capacity of $1.036 billion that matures in June 2011. As of September 30, 2009, $818.9 million was outstanding under the bank credit facility, including $142.4 million of letters of credit, leaving approximately $216.6 million available for future borrowing. The Partnership’s borrowing capacity was reduced to $862.2 million on October 1, 2009 due to the $173.3 million prepayment from proceeds of the Treating assets disposition but the amount available for future borrowing of $216.6 million was unchanged. The bank credit facility is guaranteed by certain of the Partnership’s subsidiaries.
The Partnership’s bank credit facility has satisfied a leverage fee payment requirement that would have triggered if it had not prepaid debt and permanently reduce the banks’ commitments and senior secured note borrowings by the cumulative amounts of $100.0 million on September 30, 2009, $200.0 million on December 31, 2009 and $300.0 million on March 31, 2010. In order to avoid this fee, the Partnership reduced its bank commitments and senior secured note borrowings by $212.0 million in August 2009 with proceeds from the disposition of Alabama, Mississippi and south Texas assets and by $258.1 million with proceeds from the disposition of Treating assets in October 2009. These payments satisfied the de-leveraging targets for September and December 2009 and March 2010. As of October 1, 2009, after giving effect to these repayments of long-term debt and the reduction of commitments under the Partnership’s bank credit facility as a result of such repayments, the Partnership had a bank credit facility with a borrowing capacity of $862.2 million and $327.8 million (including PIK) of outstanding senior secured notes.
Recent Accounting Pronouncements
FASB ASC 805 and FASB ASC 810-10-65-1 were issued December 2007. FASB ASC 805 requires most identifiable assets, liabilities, non-controlling interests and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under FASB ASC 805, all business combinations will be accounted for by applying the acquisition method. FASB ASC 805 is effective for periods beginning on or after December 15, 2008. FASB ASC 810-10-65-1 requires non-controlling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. FASB ASC 810-10-65-1 was adopted January 1, 2009 and comparative period information has been recast to classify non-controlling interests in equity and attribute net income and other comprehensive income to non-controlling interests.
FASB ASC 815-10-65-1 was issued in March 2008 and requires entities to provide greater transparency about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for under FASB ASC 815 and how the instruments and related hedged items affect the financial position, results of operations and cash flows of the entity. FASB ASC 815-10-65-1 is effective for fiscal years beginning after November 15, 2008. FASB ASC 815-10-65-1 was adopted effective January 1, 2009 and the Partnership added the required disclosures.
FASB ASC 105 was released July 1, 2009 and intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements of non-governmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America. SFAS No. 162 has been superseded by SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (the Codification) released July 1, 2009. The Codification became the exclusive authoritative reference for non-governmental U.S. GAAP for use in financial statements issued for interim and annual periods ending after September 15, 2009, except for Securities and Exchange Commission (SEC) rules and interpretive releases, which are also authoritative GAAP for SEC registrants. The change establishes non-governmental U.S. GAAP into the authoritative Codification and guidance that is non-authoritative. The contents of the Codification carry the same level of authority, eliminating the four-level GAAP hierarchy previously set forth in Statement 162. The Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in the Codification has become non-authoritative. The Company has revised all GAAP references to reflect the Codification for the quarter ending September 30, 2009.

 

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FASB ASC 260-10-45-60 was issued in June 2008 and requires unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents to be treated as participating securities as defined in FASB ASC 260-10-20 and, therefore, included in the earnings allocation in computing earnings per share under the two-class method described in FASB ASC 260. FASB ASC 260-10-45-60 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. The Company adopted FASB ASC 260-10-45-60 effective January 1, 2009 and adjusted all prior reporting periods to conform to the requirements.
In June 2009 FASB ASC 810-10-05-8 was issued. It requires reporting entities to evaluate former Qualifying Special Purpose Entities or QSPEs for consolidation, changes the approach to determining a variable interest entity’s (VIE) primary beneficiary from a quantitative assessment to a qualitative assessment designed to identify a controlling financial interest, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the characteristics that identify a VIE. This Statement requires additional year-end and interim disclosures for public and nonpublic companies that are similar to the disclosures required by FASB ASC 860-10-65-2. The Statement is effective for fiscal years beginning after November 15, 2009 and for subsequent interim and annual reporting periods. The Company does not expect this statement to have a significant impact to its financial statements.
FASB ASC 855 was issued in June 2009 and is effective for interim or annual financial periods ending after June 15, 2009 and addresses accounting and disclosure requirements related to subsequent events. The statement requires management to evaluate subsequent events through the date the financial statements are issued. Companies are required to disclose the date through which subsequent events have been evaluated. The Company has taken this statement into consideration.
FASB ASC 825-10-65-1 requires publicly traded companies to disclose the fair value of financial instruments within the scope of FASB ASC 825 in interim financial statements, adding to the current requirement to make those disclosures in annual financial statements. FASB ASC 825-10-65-1 is effective for interim and annual periods ending after June 15, 2009. The Company has added the required footnote disclosure.
Disclosure Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of the federal securities laws that are based on information currently available to management as well as management’s assumptions and beliefs. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Such statements reflect our current views with respect to future events based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to specific uncertainties discussed elsewhere in this Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008, and those set forth in Part II, “Item 1A. Risk Factors” of this report, if any, may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.
Item 3.   Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The Partnership’s primary market risk is the risk related to changes in the prices of natural gas and NGLs. In addition, it is exposed to the risk of changes in interest rates on floating rate debt.

 

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Interest Rate Risk
The Partnership is exposed to interest rate risk on its variable rate bank credit facility. At September 30, 2009, the bank credit facility had outstanding borrowings of $676.5 million which approximated fair value. The Partnership manages a portion of its interest rate exposure on variable rate debt by utilizing interest rate swaps, which allows conversion of a portion of variable rate debt into fixed rate debt. In January 2008, the Partnership amended its existing interest rate swaps covering $450.0 million of the variable rate debt to extend the period by one year (coverage periods end from November 2010 through October 2011) and reduce the interest rates to a range of 4.38% to 4.68%. In September 2008, the Partnership entered into additional interest rate swaps covering the $450.0 million that converted the floating rate portion of the original swaps from three month LIBOR to one month LIBOR. As of September 30, 2009, the fair value of these interest rate swaps was reflected as a liability of $28.0 million ($18.2 million in net current liabilities and $9.8 million in long-term liabilities) on the financial statements. The Partnership estimates that a 1% increase or decrease in the interest rate would increase or decrease the fair value of these interest rate swaps by approximately $14.8 million. Considering the interest rate swaps and the amount outstanding on its bank credit facility as of September 30, 2009, the Partnership estimates that a 1% increase or decrease in the interest rate would change its annual interest expense by approximately $2.3 million for annual periods when the entire portion of the $450.0 million of interest rate swaps are outstanding and $6.8 million for annual periods after 2011 when all the interest rate swaps lapse.
At September 30, 2009, the Partnership had total fixed rate debt obligations of $409.2 million, consisting of its senior secured notes (including PIK) with a weighted average interest rate of 10.5%. The fair value of these fixed rate obligations was approximately $392.1 million as of September 30, 2009. The Partnership estimates that a 1% increase or decrease in interest rates would increase or decrease the fair value of the fixed rate debt (its senior secured notes including PIK) by $10.8 million based on the debt obligations as of September 30, 2009.
Commodity Price Risk
The Partnership is subject to significant risks due to fluctuations in commodity prices. Its exposure to these risks is primarily in the gas processing component of its business. The Partnership currently processes gas under three main types of contractual arrangements:
  1.   Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) in processing. The Partnership’s margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership mitigates its risk of processing natural gas when its margins are negative under its current processing margin contracts primarily through its ability to bypass processing when it is not profitable for the Partnership or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.
  2.   Percent of liquids contracts: Under these contracts, the Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, its margins from these contracts are greater during periods of high liquids prices. The Partnership’s margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.
  3.   Fee based contracts: Under these contracts the Partnership has no commodity price exposure, and is paid a fixed fee per unit of volume that is treated or conditioned.
The gross margin presentation in the table below is calculated net of results from discontinued operations. Gas processing margins by contract type and gathering and transportation margins as a percent of total gross margin for the comparative quarterly and year-to-date periods are as follows:
                                 
    For the Three Months Ended     For the Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Gathering and transportation margin
    63.8 %     42.2 %     67.1 %     51.5 %
 
                               
Gas processing margins:
                               
Processing margin
    10.6 %     26.4 %     8.0 %     19.7 %
Percent of liquids
    12.8 %     24.2 %     12.8 %     20.2 %
Fee based
    12.8 %     7.2 %     12.1 %     8.6 %
 
                       
Total gas processing margins
    36.2 %     57.8 %     32.9 %     48.5 %
 
                       
 
                               
Total
    100.0 %     100.0 %     100.0 %     100.0 %
 
                       

 

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The Partnership has hedges in place at September 30, 2009 covering liquids volumes it expects to receive under percent of liquids (POL) contracts as set forth in the following tables. The relevant payment index price is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).
                         
        Notional   Partnership   Partnership   Fair Value  
Period   Underlying   Volume   Pays   Receives*   Asset/(Liability)  
                    (In thousands)  
October 2009–December 2009
  Ethane   34 (MBbls)   Index   $0.6401/gal   $ 180  
October 2009–December 2009
  Propane   27 (MBbls)   Index   $1.2771/gal     369  
October 2009–December 2009
  Iso Butane   5 (MBbls)   Index   $1.7179/gal     120  
October 2009–December 2009
  Normal Butane   10 (MBbls)   Index   $1.5320/gal     146  
October 2009–December 2009
  Natural Gasoline   20 (MBbls)   Index   $2.0257/gal     502  
 
                     
 
                  $ 1,317  
 
                     
                         
        Notional   Partnership   Partnership   Fair Value  
Period   Underlying   Volume   Pays   Receives*   Asset/(Liability)  
                    (In thousands)  
January 2010–December 2010
  Propane   109 (MBbls)   Index   $0.9584/gal   $ 5  
January 2010–December 2010
  Normal Butane   40 (MBbls)   Index   $1.2580/gal     93  
January 2010–December 2010
  Natural Gasoline   21 (MBbls)   Index   $1.4815/gal     14  
 
             
 
                  $ 112  
 
                     
     
*   weighted average
The Partnership has hedged its exposure to declines in prices for NGL volumes produced for its account. The NGL volumes hedged, as set forth above, focus on POL contracts. The Partnership hedges POL exposure based on volumes considered hedgeable (volumes committed under contracts that are long term in nature) versus total POL volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month to month processing options. The Partnership hedged 66.3% of its hedgeable volumes at risk through the end of 2009 (37.2% of total volumes at risk through the end of 2009). The Partnership has also hedged 46.5% of its hedgeable natural gasoline volumes for 2010 (17.9% of total natural gasoline volumes at risk for 2010).
The Partnership also has hedges in place at September 30, 2009 covering the fractionation spread risk related to its processing margin contracts as set forth in the following table:
                             
        Notional   Partnership     Partnership   Fair Value  
Period   Underlying   Volume   Pays   Receives     Asset/(Liability)  
                        (In thousands)  
October 2009 – December 2009
  Ethane   39 (MBbls)   Index   $0.44/gal*   $ (118 )
October 2009 – December 2009
  Propane   24 (MBbls)   Index   $0.8148/gal*     (137 )
October 2009 – December 2009
  Iso-Butane   1 (MBbls)   Index   $1.105/gal*     (2 )
October 2009 – December 2009
  Normal Butane   15 (MBbls)   Index   $1.0263/gal*     (108 )
October 2009 – December 2009
  Natural Gasoline   16 (MBbls)   Index   $1.385/gal*     (29 )
October 2009 – December 2009
  Natural Gas   4,822 (MMBtu/d)   $4.8225/MMBtu*   Index     32  
 
                         
 
                      $ (362 )
 
                         
                                         
            Notional     Partnership     Partnership     Fair Value  
Period   Underlying     Volume     Pays     Receives     Asset/(Liability)  
                                    (In thousands)  
January 2010 – December 2010
  Ethane   127 (MBbls)   Index   $0.4607/gal*   $ (307 )
January 2010 – December 2010
  Propane   85 (MBbls)   Index   $0.9226/gal*     (116 )
January 2010 – December 2010
  Normal Butane   57 (MBbls)   Index   $1.2007gal*     (1 )
January 2010 – December 2010
  Natural Gasoline   56 (MBbls)   Index   $1.5305/gal*     140  
January 2010 – December 2010
  Natural Gas   4,269 (MMbtu/d)   $5.7672/MMBtu*   Index     617  
 
                                     
 
                                  $ 333  
 
                                     
     
*   weighted average
The Partnership is also subject to price risk to a lesser extent for fluctuations in natural gas prices with respect to a portion of its gathering and transport services. Less than 3.0% of the natural gas the Partnership markets is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the natural gas at a percentage of the index price, resale margins are higher during periods of high natural gas prices and lower during periods of lower natural gas prices. The Partnership has hedged 36.6% of its natural gas volumes at risk through the end of 2009.

 

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Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves the Partnership with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.
The Partnership’s primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a risk management committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by the risk management committee.
The use of financial instruments may expose the Partnership to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.
As of September 30, 2009, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value asset of $4.7 million. The aggregate effect of a hypothetical 10% increase in gas and NGL prices would result in a decrease of approximately $1.8 million in the net fair value asset of these contracts as of September 30, 2009.
Item 4.   Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2009 in alerting them in a timely manner to material information required to be disclosed in our reports filed with the Securities and Exchange Commission.
(b) Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting that occurred in the three months ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II—OTHER INFORMATION
Item 1.   Legal Proceedings
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.
For a discussion of certain litigation and similar proceedings, please refer to Note 11, “Commitments and Contingencies,” of the Notes to Consolidated Consolidated Financial Statements, which is incorporated by reference herein.
Item 1A.   Risk Factors
Information about risk factors for the three months ended September 30, 2009 does not differ materially from that set forth in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2008.

 

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Item 5.   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
  2.1†      
Partnership Interest Purchase and Sale Agreement, dated as of June 9, 2009, among Crosstex Energy Services, L.P., Crosstex Energy Services GP, LLC, Crosstex CCNG Gathering, Ltd., Crosstex CCNG Transmission Ltd., Crosstex Gulf Coast Transmission Ltd., Crosstex Mississippi Pipeline, L.P., Crosstex Mississippi Gathering, L.P., Crosstex Mississippi Industrial Gas Sales, L.P., Crosstex Alabama Gathering System, L.P., Crosstex Midstream Services, L.P., Javelina Marketing Company Ltd., Javelina NGL Pipeline Ltd. and Southcross Energy LLC (incorporated by reference to Exhibit 2.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated June 9, 2009, filed with the Commission on June 11, 2009).
  2.2†      
Partnership Interest Purchase and Sale Agreement, dated as of August 28, 2009, among Crosstex Energy Services, L.P., Crosstex Energy Services GP, LLC, Crosstex Treating Services, L.P. and KM Treating GP LLC (incorporated by reference to Exhibit 2.1 to Crosstex Energy, L.P.’s current report on Form 8-K dated August 28, 2009, filed with the Commission on September 3, 2009).
  3.1      
Amended and Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006).
  3.2      
Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated March 22, 2006, filed with the Commission on March 28, 2006).
  3.3      
Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.4      
Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s current report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
  3.5      
Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).
  3.6      
Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated March 23, 2008 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).
  3.7      
Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.8      
Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, file No. 0-50067).
  3.9      
Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.10      
Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.11      
Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.12      
Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  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.
 
  In accordance with the instructions to Item 601(b)(2) of Regulation S-K, the exhibits and schedules to Exhibits 2.1 and 2.2 are not filed herewith. The agreements identify such exhibits and schedules, including the general nature of their content. We undertake to provide such exhibits and schedules to the Commission upon request.

 

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  CROSSTEX ENERGY, INC.
 
 
November 6, 2009  By:   /s/ WILLIAM W. DAVIS    
    William W. Davis,   
    Executive Vice President and
Chief Financial Officer
 
 

 

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EXHIBIT INDEX
             
Number       Description
  2.1†      
Partnership Interest Purchase and Sale Agreement, dated as of June 9, 2009, among Crosstex Energy Services, L.P., Crosstex Energy Services GP, LLC, Crosstex CCNG Gathering, Ltd., Crosstex CCNG Transmission Ltd., Crosstex Gulf Coast Transmission Ltd., Crosstex Mississippi Pipeline, L.P., Crosstex Mississippi Gathering, L.P., Crosstex Mississippi Industrial Gas Sales, L.P., Crosstex Alabama Gathering System, L.P., Crosstex Midstream Services, L.P., Javelina Marketing Company Ltd., Javelina NGL Pipeline Ltd. and Southcross Energy LLC (incorporated by reference to Exhibit 2.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated June 9, 2009, filed with the Commission on June 11, 2009).
  2.2†      
Partnership Interest Purchase and Sale Agreement, dated as of August 28, 2009, among Crosstex Energy Services, L.P., Crosstex Energy Services GP, LLC, Crosstex Treating Services, L.P. and KM Treating GP LLC (incorporated by reference to Exhibit 2.1 to Crosstex Energy, L.P.’s current report on Form 8-K dated August 28, 2009, filed with the Commission on September 3, 2009).
  3.1      
Amended and Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006).
  3.2      
Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated March 22, 2006, filed with the Commission on March 28, 2006).
  3.3      
Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.4      
Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s current report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
  3.5      
Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).
  3.6      
Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated March 23, 2008 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).
  3.7      
Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.8      
Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, file No. 0-50067).
  3.9      
Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.10      
Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.11      
Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.12      
Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  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.
 
  In accordance with the instructions to Item 601(b)(2) of Regulation S-K, the exhibits and schedules to Exhibits 2.1 and 2.2 are not filed herewith. The agreements identify such exhibits and schedules, including the general nature of their content. We undertake to provide such exhibits and schedules to the Commission upon request.

 

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