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EX-31.2 - EXHIBIT 31.2 - CROSSTEX ENERGY INCc00195exv31w2.htm
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EX-31.1 - EXHIBIT 31.1 - CROSSTEX ENERGY INCc00195exv31w1.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 March 31, 2010
OR
     
o   Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ________ to ________
Commission file number: 000-50536
CROSSTEX ENERGY, INC.
(Exact name of registrant as specified in its charter)
     
Delaware   52-2235832
(State of organization)   (I.R.S. Employer Identification No.)
     
2501 CEDAR SPRINGS    
DALLAS, TEXAS   75201
(Address of principal executive offices)   (Zip Code)
(214) 953-9500
(Registrant’s telephone number, including area code)
Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 o   Accelerated filer þ   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 Act). Yes o No þ
As of April 30, 2010, the Registrant had 46,575,010 shares of common stock outstanding.
 
 

 

 


 

TABLE OF CONTENTS
         
Item   Page  
 
DESCRIPTION
 
       
PART I—FINANCIAL INFORMATION
 
       
1. FINANCIAL STATEMENTS
    3  
 
       
    25  
 
       
    32  
 
       
    35  
 
       
PART II—OTHER INFORMATION
 
       
    35  
 
       
    35  
 
       
    35  
 
       
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1

 

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CROSSTEX ENERGY, INC.

Condensed Consolidated Balance Sheets
                 
    March 31,     December 31,  
    2010     2009  
    (Unaudited)          
    (In thousands)  
ASSETS
       
Current assets:
               
Cash and cash equivalents
  $ 6,561     $ 10,703  
Accounts and notes receivable, net:
               
Trade, accrued revenue and other
    201,963       214,750  
Fair value of derivative assets
    8,366       9,112  
Natural gas and natural gas liquids, prepaid expenses and other
    12,131       14,692  
 
           
 
               
Total current assets
    229,021       249,257  
 
           
 
               
Property and equipment, net of accumulated depreciation of $272,480 and $259,057, respectively
    1,239,300       1,280,197  
Fair value of derivative assets
    6,168       5,665  
Intangible assets, net of accumulated amortization of $124,681 and $115,813, respectively
    526,028       534,897  
Other assets, net
    30,756       10,217  
 
           
 
               
Total assets
  $ 2,031,273     $ 2,080,233  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
       
Current liabilities:
               
Accounts payable, drafts payable and accrued gas purchases
  $ 170,536     $ 179,710  
Fair value of derivative liabilities
    12,468       30,337  
Current portion of long-term debt
    10,995       28,602  
Other current liabilities
    39,821       52,399  
 
           
 
               
Total current liabilities
    233,820       291,048  
 
           
 
               
Long-term debt
    755,148       845,100  
Other long-term liabilities
    20,252       20,797  
Deferred tax liability
    92,237       95,272  
Fair value of derivative liabilities
    5,927       12,106  
Commitments and contingencies
    ¾       ¾  
Stockholders’ equity
    923,889       815,910  
 
           
 
               
Total liabilities and stockholders’ equity
  $ 2,031,273     $ 2,080,233  
 
           
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.

Consolidated Statements of Operations
                 
    Three Months Ended March 31,  
    2010     2009  
    (Unaudited)  
    (In thousands, except per share  
    amounts)  
Revenues:
               
Midstream
  $ 432,452     $ 352,437  
Gas and NGL marketing activities
    2,340       721  
 
           
Total revenues
    434,792       353,158  
 
           
Operating costs and expenses:
               
Purchased gas
    353,597       284,212  
Operating expenses
    26,465       27,879  
General and administrative
    13,481       14,500  
Gain on sale of property
    (14,343 )     (828 )
(Gain) loss on derivatives
    3,696       (4,336 )
Impairments
    998       ¾  
Depreciation and amortization
    27,110       28,777  
 
           
Total operating costs and expenses
    411,004       350,204  
 
           
Operating income
    23,788       2,954  
Other income (expense):
               
Interest expense, net of interest income
    (26,855 )     (17,534 )
Loss on extinguishment of debt
    (14,713 )     (4,669 )
Other income (expense)
    182       (22 )
 
           
Total other income (expense)
    (41,386 )     (22,225 )
 
           
Loss from continuing operations before income taxes
    (17,598 )     (19,271 )
Income tax (provision) benefit from continuing operations
    2,585       (2,041 )
 
           
Loss from continuing operations
    (15,013 )     (21,312 )
Income from discontinued operations, net of tax of $0 and $(484), respectively
    ¾       3,265  
 
           
Net loss
    (15,013 )     (18,047 )
 
           
Less: Interest of non-controlling partners in the Partnership’s net loss:
               
Interest of non-controlling partners in the Partnership’s continuing operations
    (9,611 )     (11,648 )
Interest of non-controlling partners in the Partnership’s discontinued operations
    ¾       2,443  
 
           
Total interest of non-controlling partners in the Partnership
    (9,611 )     (9,205 )
 
           
Net loss attributable to Crosstex Energy, Inc.
  $ (5,402 )   $ (8,842 )
 
           
Net loss per common share:
               
Basic and diluted
  $ (0.11 )   $ (0.19 )
 
           
Weighted average shares outstanding:
               
Basic and diluted
    46,575       46,439  
 
           
Amounts attributable to Crosstex Energy, Inc. common shareholders:
               
Loss from continuing operations, net of tax and non-controlling interest
  $ (5,402 )   $ (9,664 )
Discontinued operations, net of tax and non-controlling interest
          822  
 
           
Net loss attributable to Crosstex Energy, Inc.
  $ (5,402 )   $ (8,842 )
 
           
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.
Consolidated Statement of Changes in Stockholders’ Equity
Three Months Ended March 31, 2010
                                                         
                                    Accumulated              
                    Additional     Retained     Other     Non-     Total  
    Common Stock     Paid In     Earnings     Comprehensive     Controlling     Stockholders’  
    Shares     Amount     Capital     (Deficit)     Income     Interest     Equity  
    (Unaudited)  
    (In thousands)  
 
 
Balance, December 31, 2009
    46,524     $ 464     $ 271,669     $ (43,279 )   $ (568 )   $ 587,624     $ 815,910  
Issuance of units by the Partnership to non-controlling interest
    ¾       ¾       ¾       ¾       ¾       120,786       120,786  
Change in equity due to issuance of units by the Partnership
    ¾       ¾       (32,769 )     ¾       115       32,586       (68 )
Stock-based compensation
    ¾       ¾       1,160       ¾       ¾       1,424       2,584  
Net loss
    ¾       ¾       ¾       (5,402 )     ¾       (9,611 )     (15,013 )
Conversion of restricted stock to common, net of shares withheld for taxes
    51       1       (130 )     ¾       ¾       ¾       (129 )
Hedging gains or losses reclassified to earnings
    ¾       ¾       ¾       ¾       238       1,024       1,262  
Adjustment in fair value of derivatives
    ¾       ¾       ¾       ¾       70       303       373  
Non-controlling partners’ impact of conversion of restricted units and option exercises
    ¾       ¾       ¾       ¾       ¾       (1,632 )     (1,632 )
Distributions to non-controlling interest
    ¾       ¾       ¾       ¾       ¾       (184 )     (184 )
 
                                         
Balance, March 31, 2010
    46,575     $ 465     $ 239,930     $ (48,681 )   $ (145 )   $ 732,320     $ 923,889  
 
                                         

 

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CROSSTEX ENERGY, INC.

Consolidated Statements of Comprehensive Income
                 
    Three Months Ended March 31,  
    2010     2009  
    (Unaudited)  
    (In thousands)  
       
Net loss
  $ (15,013 )   $ (18,047 )
Non-controlling partners’ share of other comprehensive income in the Partnership, net of taxes of $68
    115       ¾  
Hedging gains (losses) reclassified to earnings, net of taxes of $140 and $(537), respectively
    238       (912 )
Adjustment in fair value of derivatives, net of taxes of $41 and $(40), respectively
    70       (67 )
 
           
Comprehensive loss
    (14,590 )     (19,026 )
Comprehensive loss attributable to the non-controlling interest
    (9,611 )     (9,205 )
 
           
Comprehensive loss attributable to Crosstex Energy, Inc.
  $ (4,979 )   $ (9,821 )
 
           
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.

Consolidated Statements of Cash Flows
                 
    Three Months Ended March 31,  
    2010     2009  
    (Unaudited)  
    (In thousands)  
Cash flows from operating activities:
               
Net loss
  $ (15,013 )   $ (18,047 )
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
               
Depreciation and amortization
    27,110       34,735  
Gain on sale of property
    (14,343 )     (879 )
Impairments
    998       ¾  
Deferred tax expense (benefit)
    (3,285 )     1,813  
Non-cash stock-based compensation
    2,584       1,632  
Amortization of debt issue costs
    2,128       1,439  
Amortization of discount on notes
    263          
Derivatives mark to market interest rate settlement
    (24,160 )      
Non-cash derivatives loss
    2,288       202  
Non-cash loss on debt extinguishment
    5,396       4,669  
Payment of debt from interest paid-in-kind
    (11,558 )     ¾  
Changes in assets and liabilities:
               
Accounts receivable, accrued revenue and other
    12,701       95,915  
Natural gas, natural gas liquids , prepaid expenses and other
    2,214       2,522  
Accounts payable, accrued gas purchases, and other accrued liabilities
    (12,646 )     (113,968 )
 
           
Net cash provided by (used in) operating activities
    (25,323 )     10,033  
 
           
Cash flows from investing activities:
               
Additions to property and equipment
    (9,670 )     (48,708 )
Insurance recoveries on property and equipment
    874       3,115  
Proceeds from sale of property
    39,675       11,019  
 
           
Net cash provided by (used in) investing activities
    30,879       (34,574 )
 
           
Cash flows from financing activities:
               
Proceeds from borrowings
    809,862       189,550  
Payments on borrowings
    (908,160 )     (118,903 )
Proceeds from capital lease obligations
    ¾       1,489  
Payments on capital lease obligations
    (556 )     (624 )
Decrease in drafts payable
    (1,622 )     (21,514 )
Debt refinancing costs
    (28,063 )     (13,364 )
Distributions to non-controlling partners in the Partnership
    (184 )     (7,488 )
Common dividends paid
    ¾       (4,234 )
Partnership equity transactions
    (1,632 )     (64 )
Conversion of restricted stock, net of shares withheld for taxes
    (129 )     (268 )
Proceeds from issuance of Partnership units
    120,786       ¾  
 
           
Net cash provided by (used in) financing activities
    (9,698 )     24,580  
 
           
Net increase (decrease) in cash and cash equivalents
    (4,142 )     39  
Cash and cash equivalents, beginning of period
    10,703       13,959  
 
           
Cash and cash equivalents, end of period
  $ 6,561     $ 13,998  
 
           
Cash paid for interest
  $ 22,974     $ 17,333  
Cash paid (refund) from income taxes
  $ 1,195     $ (178 )
See accompanying notes to condensed consolidated financial statements.

 

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CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)
(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 year to conform to the current presentation. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2009.
(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
In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-06, Improving Disclosures about Fair Value Measurements, which amends FASB ASC Topic 820, Fair Value Measurements and Disclosures. The ASU requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information about purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. The ASU also clarifies existing fair-value measurement disclosure guidance about the level of disaggregation, inputs, and valuation techniques. The Company has evaluated the ASU and determined that it is not currently impacted by the update.
(2) Asset Dispositions
The Partnership sold its Midstream assets in Alabama, Mississippi and south Texas for $217.6 million in August 2009. Sales proceeds, net of transaction costs and other obligations associated with the sale, of $212.0 million were used to repay long-term indebtedness and the Partnership recognized a gain on sale of $97.2 million. On October 1, 2009, the Partnership sold its Treating assets for net proceeds of $265.4 million. Sales proceeds, net of transaction costs and other obligations associated with the sale, of $258.1 million were used to repay long-term indebtedness and the Partnership recognized a gain on sale of $86.3 million.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
The revenues, operating expenses, general and administrative expenses associated directly with the sold assets, depreciation and amortization expense, allocated income taxes and an allocated interest expense related to the operations of the sold assets have been segregated from continuing operations and reported as discontinued operations for the three months ended March 31, 2009. Interest expense of $9.1 million for the three months ended March 31, 2009 was allocated to discontinued operations related to the debt repaid from the proceeds from the asset dispositions using average historical interest rates. 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  
    March 31, 2009  
Midstream revenues
  $ 179,200  
Treating revenues
    16,277  
Income from discontinued operations, net of tax
    3,265  
(3) Long-Term Debt
As of March 31, 2010 and December 31, 2009, long-term debt consisted of the following (in thousands):
                 
    March 31,     December 31,  
    2010     2009  
Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rate (per the facility) at December 31, 2009 was 6.75%
  $ ¾     $ 529,614  
New credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rate (per the new facility) at March 31, 2010 was 4.66%
    38,000       ¾  
Senior secured notes (including PIK notes (1) of $9.5 million), weighted average interest rate at December 31, 2009 was 10.5%
    ¾       326,034  
Senior unsecured notes, net of discount of $14,911, which bear interest at the rate of 8.875%
    710,089       ¾  
Series B secured note assumed in the Eunice transaction, which bears interest at the rate of 9.5%
    18,054       18,054  
 
           
 
    766,143       873,702  
Less current portion
    (10,995 )     (28,602 )
 
           
Debt classified as long-term
  $ 755,148     $ 845,100  
 
           
     
(1)   The senior secured notes began accruing additional interest of 1.25% per annum in February 2009 (the “PIK notes”) in the form of an increase in the principal amounts unless the leverage ratio is less than 4.25 to 1.00 at the end of any fiscal quarter. These notes were paid in full in February 2010.
New Credit Facility. In February 2010, the Partnership amended and restated its existing secured bank credit facility with a new syndicated secured bank credit facility (the “new credit facility”). The new credit facility has a borrowing capacity of $420.0 million and matures in February 2014. Net proceeds from the new credit facility along with net proceeds from the senior unsecured notes discussed under “Senior Unsecured Notes” below were used to, among other things, repay the Partnership’s credit facility and senior secured notes including PIK notes in February 2010. The Partnership recognized a loss on extinguishment of debt of $14.7 million when the debt was repaid due to make-whole interest payments on the senior secured debt of $9.3 million and the write-off of unamortized debt costs of $5.4 million. Debt refinancing costs totaling $28.1 million associated with new borrowings, including the senior unsecured notes, are included in other noncurrent assets as of March 31, 2010 and amortized to interest expense over the term of the related debt.
As of March 31, 2010, $187.5 million was outstanding under the new bank credit facility, including $149.5 million of letters of credit, leaving approximately $232.5 million available for future borrowing.
The new credit facility is guaranteed by substantially all of the Partnership’s subsidiaries and is secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors, including all material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of the Partnership’s equity interests in substantially all of its subsidiaries.
The Partnership may prepay all loans under the new credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The new credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, extraordinary receipts, equity issuances and debt incurrences, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the new credit facility.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
Under the new credit facility, borrowings bear interest at the Partnership’s option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. The Partnership pays a per annum fee on all letters of credit issued under the new credit facility and a commitment fee of 0.50% per annum on the unused availability under the new credit facility. The letter of credit fee and the applicable margins for the interest rate vary quarterly based on the leverage ratio (as defined in the new credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows:
                         
            Eurodollar Rate     Letter of Credit  
Leverage Ratio   Base Rate Loans     Loans     Fees  
Greater than or equal to 5.00 to 1.00
    3.25 %     4.25 %     4.25 %
Greater than or equal to 4.50 to 1.00 and less than 5.00 to 1.00
    3.00 %     4.00 %     4.00 %
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00
    2.75 %     3.75 %     3.75 %
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00
    2.50 %     3.50 %     3.50 %
Less than 3.50 to 1.00
    2.25 %     3.25 %     3.25 %
Based on the forecasted leverage ratio for 2010, the Partnership expects the applicable margin for the interest rate and letter of credit fee to be at the mid-point of these ranges. The new credit facility does not have a floor for the Base Rate or the Eurodollar Rate.
The new credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter (except for the interest coverage ratio, which builds to a four-quarter test during 2010).
The maximum permitted leverage ratio is as follows:
 
    5.75 to 1.00 for the fiscal quarters ending March 31, 2010 and June 30, 2010;
 
    5.50 to 1.00 for the fiscal quarter ending September 30, 2010;
 
    5.25 to 1.00 for the fiscal quarter ending December 31, 2010;
 
    5.00 to 1.00 for the fiscal quarter ending March 31, 2011;
 
    4.75 to 1.00 for the fiscal quarter ending June 30, 2011; and
 
    4.50 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.
The maximum permitted senior leverage ratio (as defined in the new credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges), is 2.50 to 1.00.
The minimum consolidated interest coverage ratio (as defined in the new credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is as follows:
 
    1.50 to 1.00 for the fiscal quarter ending March 31, 2010;
 
    1.75 to 1.00 for the fiscal quarters ending June 30, 2010 through December 31, 2010;
 
    2.00 to 1.00 for the fiscal quarter ending March 31, 2011;
 
    2.25 to 1.00 for the fiscal quarter ending June 30, 2011; and
 
    2.50 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
In addition, the new credit facility contains various covenants that, among other restrictions, limit the Partnership’s ability to:
    grant or assume liens;
 
    make investments;
 
    incur or assume indebtedness;
 
    engage in mergers or acquisitions;
 
    sell, transfer, assign or convey assets;
 
    repurchase its equity, make distributions and certain other restricted payments;
 
    change the nature of its business;
 
    engage in transactions with affiliates;
 
    enter into certain burdensome agreements;
 
    make certain amendments to the omnibus agreement or its subsidiaries’ organizational documents;
 
    prepay the senior unsecured notes and certain other indebtedness; and
 
    enter into certain hedging contracts.
The new credit facility permits the Partnership to make quarterly distributions to unitholders so long as no default exists under the new credit facility.
Each of the following is an event of default under the new credit facility:
    failure to pay any principal, interest, fees, expenses or other amounts when due;
 
    failure to meet the quarterly financial covenants;
 
    failure to observe any other agreement, obligation, or covenant in the new credit facility or any related loan document, subject to cure periods for certain failures;
 
    the failure of any representation or warranty to be materially true and correct when made;
 
    the Partnership or any of its subsidiaries’ default under other indebtedness that exceeds a threshold amount;
 
    judgments against the Partnership or any of its material subsidiaries, in excess of a threshold amount;
 
    certain ERISA events involving the Partnership or any of its material subsidiaries, in excess of a threshold amount;
 
    bankruptcy or other insolvency events involving the Partnership or any of its material subsidiaries; and
 
    a change in control (as defined in the new credit facility).
If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness under the new credit facility will immediately become due and payable. If any other event of default exists under the new credit facility, the lenders may accelerate the maturity of the obligations outstanding under the new credit facility and exercise other rights and remedies. In addition, if any event of default exists under the new credit facility, the lenders may commence foreclosure or other actions against the collateral.
If any default occurs under the new credit facility, or if the Partnership is unable to make any of the representations and warranties in the new credit facility, the Partnership will be unable to borrow funds or have letters of credit issued under the new credit facility.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
The Partnership is subject to interest rate risk on its new credit facility and may enter into interest rate swaps to reduce this risk.
The Partnership expects to be in compliance with the covenants in the new credit facility for the next twelve months.
Series B Secured Note. On October 20, 2009, the Partnership acquired the Eunice natural gas liquids processing plant and fractionation facility which includes an $18.1 million series B secured note. This note bears an interest rate of 9.5%. Payments including interest of $12.2 million and $7.4 million are due in 2010 and 2011, respectively.
Senior Unsecured Notes. On February 10, 2010, the Partnership issued $725.0 million in aggregate principal amount of 8.875% senior unsecured notes (the “notes”) due on February 15, 2018 at an issue price of 97.907% to yield 9.25% to maturity. Net proceeds from the sale of the notes of $689.7 million (net of transaction costs and original issue discount), together with borrowings under the credit facility discussed above, were used to repay in full amounts outstanding under the old bank credit facility and senior secured notes and to pay related fees, costs and expenses, including the settlement of interest rate swaps associated with the existing credit facility. The notes are unsecured and unconditionally guaranteed on a senior basis by certain of the Partnership’s direct and indirect wholly-owned subsidiaries, including all of the Partnership’s current subsidiaries other than Crosstex LIG, LLC and Crosstex Tuscaloosa, LLC, its Louisiana regulated entities, and Crosstex DC Gathering, J.V. Interest payments are due semi-annually in arrears starting on August 15, 2010.
The indenture governing the notes contains covenants that, among other things, limit the Partnership’s ability and the ability of certain of its subsidiaries to:
    sell assets including equity interests in its subsidiaries;
 
    pay distributions on, redeem or repurchase units or redeem or repurchase its subordinated debt (as discussed in more detail below);
 
    make investments;
 
    incur or guarantee additional indebtedness or issue preferred units;
 
    create or incur certain liens;
 
    enter into agreements that restrict distributions or other payments from its restricted subsidiaries to the Partnership;
 
    consolidate, merge or transfer all or substantially all of its assets;
 
    engage in transactions with affiliates;
 
    create unrestricted subsidiaries;
 
    enter into sale and leaseback transactions; or
 
    engage in certain business activities.
The indenture provides that if the Partnership’s fixed charge coverage ratio (the ratio of its consolidated cash flow to its fixed charges, each as defined in the indenture) for the most recently ended four full fiscal quarters is not less than 2.0 to 1.0, the Partnership will be permitted to pay distributions to its unitholders in an amount equal to available cash from operating surplus (each as defined in the partnership agreement) with respect to the Partnership’s preceding fiscal quarter plus a number of items, including the net cash proceeds received by the Partnership as a capital contribution or from the issuance of equity interests since the date of the indenture, to the extent not previously expended. If the Partnership’s fixed charge coverage ratio is less than 2.0 to 1.0, the Partnership will be able to pay distributions to its unitholders in an amount equal to an $80.0 million basket (less amounts previously expended pursuant to such basket), plus the same number of items discussed in the preceding sentence to the extent not previously expended.
If the notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services, many of the covenants discussed above will terminate.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
The Partnership may redeem up to 35% of the notes at any time prior to February 15, 2013 with the cash proceeds from equity offerings at a redemption price of 108.875% of the principal amount of the notes (plus accrued and unpaid interest to the redemption date) provided that:
    at least 65% of the aggregate principal amount of the senior notes remains outstanding immediately after the occurrence of such redemption; and
 
    the redemption occurs within 120 days of the date of the closing of the equity offering.
Prior to February 15, 2014, the Partnership may redeem the notes, in whole or in part, at a “make-whole” redemption price. On or after February 15, 2014, the Partnership may redeem all or a part of the notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on February 15, 2014, 102.219% for the twelve-month period beginning February 15, 2015 and 100.00% for the twelve-month period beginning on February 15, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the notes.
Each of the following is an event of default under the indenture:
    failure to pay any principal or interest when due;
 
    failure to observe any other agreement, obligation, or other covenant in the indenture, subject to the cure periods for certain failures;
 
    the Partnership or any of its subsidiaries’ default under other indebtedness that exceeds a certain threshold amount;
 
    failures by the Partnership or any of its subsidiaries to pay final judgments that exceed a certain threshold amount; and
 
    bankruptcy or other insolvency events involving the Partnership or any of its material subsidiaries.
If an event of default relating to bankruptcy or other insolvency events occurs, the senior unsecured notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the senior unsecured notes may accelerate the maturity of the senior unsecured notes and exercise other rights and remedies.
(4) Other Long-Term Liabilities
The Partnership entered into 9 and 10-year capital leases for certain equipment. Assets under capital leases as of March 31, 2010 are summarized as follows (in thousands):
         
Equipment
  $ 27,192  
Less: Accumulated amortization
    (4,595 )
 
     
Net assets under capital lease.
  $ 22,597  
 
     
The following are the minimum lease payments to be made in each of the following years indicated for the capital leases in effect as of March 31, 2010 (in thousands):
         
2010
  $ 2,295  
2011 through 2014 ($3,034 annually)
    12,136  
Thereafter
    12,747  
Less: Interest
    (3,932 )
 
     
Net minimum lease payments under capital lease
    23,246  
Less: Current portion of net minimum lease payments
    (2,994 )
 
     
Long-term portion of net minimum lease payments
  $ 20,252  
 
     

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
(5) Certain Provisions of the Partnership Agreement
(a) Sale of Preferred Units
On January 19, 2010, the Partnership issued approximately $125.0 million of Series A Convertible Preferred Units to an affiliate of Blackstone/GSO Capital Solutions for net proceeds of $120.8 million. Crosstex Energy, GP, L.P. made a general partner contribution of $2.6 million in connection with the issuance to maintain its 2% general partner interest. The 14,705,882 preferred units are convertible by the holders thereof at any time into common units on a one-for-one basis, subject to certain adjustments in the event of certain dilutive issuances of common units. The Partnership has the right to force conversion of the preferred units after three years if (i) the daily volume-weighted average trading price of the common units is greater than 150% of the then-applicable conversion price for 20 out of the trailing 30 days ending on two trading days before the date on which the Partnership delivers notice of such conversion, and (ii) the average daily trading volume of common units must have exceeded 250,000 common units for 20 out of the trailing 30 trading days ending on two trading days before the date on which the Partnership delivers notice of such conversion. The preferred units are not redeemable but will pay a quarterly distribution that will be the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. Such quarterly distribution may be paid in cash, in additional preferred units issued in kind or any combination thereof, provided that the distribution may not be paid in additional preferred units if the Partnership pays a cash distribution on common units.
The Company reflects changes in its ownership interest in the Partnership as equity transactions. The carrying amount of the non-controlling interest is adjusted to reflect the change in the Company’s ownership interest in the Partnership. Any difference between the fair value of the consideration received and the amount by which the non-controlling interest is adjusted is recognized in additional paid-in capital. The Company’s book carrying amount per Partnership unit exceeded the price per unit received by the Partnership for its January 2010 sale of preferred units resulting in a change in equity of $32.8 million. The change of $32.8 million and $0.1 million was recorded as a reduction in additional paid-in capital within stockholders’ equity with a corresponding adjustments of $32.6 million and $0.1 million to non-controlling interest and accumulated other comprehensive income, respectively, during the three months ended March 31, 2010. The Company recorded a deferred tax asset in the amount of $12.2 million relating to this equity adjustment; however, because the Company can only realize this deferred tax asset upon liquidation of the Partnership, and to the extent of capital gains, the Company has provided a full valuation allowance against this deferred tax asset. The future conversion of the preferred units to common units will cause the Company to recognize an adjustment to the value of its tax basis in the Partnership. The Company will record the deferred tax adjustment through equity at the time of the conversion.
(b) Cash Distributions from the Partnership
Unless restricted by the terms of the Partnership’s credit facility and/or senior unsecured note indenture, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. As described under (a) Sale of Preferred Units above, the preferred units are entitled to a quarterly distribution equal to the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. The general partner is not entitled to a 2% distribution with respect to the quarterly preferred distribution of $0.2125 per unit that is made solely to the preferred unitholders. The general partner is entitled to a 2% distribution with respect to all distributions made to common unitholders. If the distributions are in excess of $0.2125 per unit, distributions are made 98% to the common and preferred unitholders and 2% 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% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48% of amounts the Partnership distributes in excess of $0.375 per unit. No incentive distributions were earned by the Company as general partner for the three months ended March 31, 2010 and 2009.
(6) Earnings per Share and Dilution Computations
Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the three months ended March 31, 2010 and 2009. The computation of diluted earnings per share further assumes the dilutive effect of common share options and restricted shares. All common share equivalents were antidilutive in the three months ended March 31, 2010 and 2009 because the Company had net losses for both periods.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements – (Continued)
The following table reflects the computation of basic earnings per share for the periods presented (in thousands except per unit amounts):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Net loss attributable to Crosstex Energy, Inc.
  $ (5,402 )   $ (8,842 )
 
           
Distributed earnings allocated to:
               
Common shares
  $ ¾     $ 4,184  
Unvested restricted shares
    ¾       50  
 
           
Total distributed earnings
  $ ¾     $ 4,234  
 
           
Undistributed loss allocated to:
               
Common shares
  $ (5,250 )   $ (12,917 )
Unvested restricted shares
    (152 )     (159 )
 
           
Total undistributed loss
  $ (5,402 )   $ (13,076 )
 
           
Net loss allocated to:
               
Common shares
  $ (5,250 )   $ (8,733 )
Unvested restricted shares
    (152 )     (109 )
 
           
Total net loss
  $ (5,402 )   $ (8,842 )
 
           
Income from discontinued operations:
               
Common shares
  $ ¾     $ 813  
Unvested restricted shares
    ¾       9  
 
           
Total income from discontinued operations
  $ ¾     $ 822  
 
           
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Basic and diluted net loss per share from continuing operations:
               
Common basic and diluted
  $ (0.11 )   $ (0.21 )
 
           
Basic and diluted net income on discontinued operations:
               
Common basic and diluted
  $ ¾     $ 0.02  
 
           
Total basic and diluted net loss per share:
               
Common basic and diluted
  $ (0.11 )   $ (0.19 )
 
           
The following are the common share amounts used to compute the basic and diluted earnings per common share for the three months ended March 31, 2010 and 2009 (in thousands):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
 
Basic and diluted earnings per share:
               
Weighted average common shares outstanding
    46,575       46,439  

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
(7) Employee Incentive Plans
(a) Long-Term Incentive Plans
The Company accounts for share-based compensation in accordance with the FASB ASC 718 which requires compensation related to all stock-based awards, including stock options, be recognized in the consolidated financial statements.
The Company and the Partnership each have similar unit or share-based payment plans for employees, which are described below. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in thousands):
                 
    Three Months Ended March 31,  
    2010     2009  
Cost of share-based compensation charged to general and administrative expense
  $ 2,162     $ 1,313  
 
           
Cost of share-based compensation charged to operating expense
    422       319  
 
           
Total amount charged to income
  $ 2,584     $ 1,632  
 
           
Interest of non-controlling partners in share-based compensation
  $ 1,032     $ 619  
 
           
Amount of related income tax benefit recognized in income
  $ 575     $ 367  
 
           
(b) Partnership Restricted Units
The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the three months ended March 31, 2010 is provided below:
                 
    Three Months Ended March 31,2010  
            Weighted  
            Average  
    Number of     Grant-Date  
    Units     Fair Value  
Crosstex Energy, L.P. Restricted Units:
               
Non-vested, beginning of period
    2,088,005     $ 7.31  
Vested*
    (731,240 )     3.44  
Forfeited
    (13,776 )     10.40  
 
           
Non-vested, end of period
    1,342,989     $ 9.20  
 
           
 
               
Aggregate intrinsic value, end of period (in thousands)
  $ 14,437          
 
             
 
     
*   Vested units include 204,651 units withheld for payroll taxes paid on behalf of employees.
The Partnership issued performance-based restricted units in 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 March 31, 2010. 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 in March 2011.
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 ended March 31, 2010 and 2009 are provided below (in thousands):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Crosstex Energy, L.P. Restricted Units:
               
Aggregate intrinsic value of units vested
  $ 6,316     $ 353  
Fair value of units vested
  $ 2,518     $ 2,301  
As of March 31, 2010, there was $6.0 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.2 years.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
(c) Partnership Unit Options
A summary of the unit option activity for the three months ended March 31, 2010 is provided below:
                 
    Three Months Ended March 31, 2010  
            Weighted  
            Average  
    Number of     Exercise  
    Units     Price  
Crosstex Energy, L.P. Unit Options:
               
Outstanding, beginning of period
    882,836     $ 6.43  
Exercised
    (29,058 )     4.78  
Forfeited
    (35,674 )     12.09  
 
           
Outstanding, end of period
    818,104     $ 6.24  
 
           
Options exercisable at end of period
    788,439     $ 6.27  
Weighted average contractual term (years) end of period:
               
Options outstanding
    8.6          
Options exercisable
    4.7          
Aggregate intrinsic value end of period (in thousands):
               
Options outstanding
  $ 4,544          
Options exercisable
  $ 379          
A summary of the unit options intrinsic value (market value in excess of exercise price at date of exercise) exercised and fair value of units vested (value per Black-Scholes option pricing model at date of grant) during the three months ended March 31, 2010 and 2009 are provided below (in thousands):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Crosstex Energy, L.P. Unit Options:
               
Intrinsic value of units options exercised
  $ 159     $ ¾  
Fair value of units vested
  $ 35     $ ¾  
As of March 31, 2010, there was $1.2 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 2.1 years.
(d) Crosstex Energy, Inc.’s Stock and Option Plan
The Company’s restricted shares are included at their fair value at the date of grant which is equal to the market value of the common stock on such date. A summary of the restricted share activity for the three months ended March 31, 2010 is provided below:
                 
    Three Months Ended March 31, 2010  
            Weighted  
            Average  
    Number of     Grant-Date  
    Shares     Fair Value  
Crosstex Energy, Inc. Restricted Shares:
               
Non-vested, beginning of period
    1,391,973     $ 9.37  
Vested*
    (44,745 )     22.92  
Forfeited
    (13,320 )     10.30  
 
           
Non-vested, end of period
    1,333,908     $ 8.73  
 
           
Aggregate intrinsic value, end of period (in thousands)
  $ 11,605          
 
             
 
     
*   Vested shares include 17,627 shares withheld for payroll taxes paid on behalf of employees
The Company issued performance-based restricted shares in 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 March 31, 2010. 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 in March 2011.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
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 months ended March 31, 2010 and 2009 are provided below (in thousands):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Crosstex Energy, Inc. Restricted Shares:
               
Aggregate intrinsic value of shares vested
  $ 315     $ 618  
Fair value of shares vested
  $ 1,026     $ 2,860  
As of March 31, 2010 there was $5.1 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 2.0 years.
CEI Stock Options
CEI stock options have not been granted as a means of compensation since 2005. All units outstanding at December 31, 2009, were vested and exercisable with all associated costs recognized. The following is a summary of the CEI stock options outstanding as of March 31, 2010:
                 
    Three Months Ended March 31, 2010  
            Weighted  
    Number of     Average  
    Units     Exercise Price  
Crosstex Energy, Inc. Stock Options:
               
Outstanding, beginning of period
    67,500     $ 9.54  
Forfeited
    (30,000 )     13.33  
 
           
Outstanding end of period
    37,500     $ 6.50  
 
           
Options exercisable at end of period
    37,500     $ 6.50  
Weighted average contractual term (years) end of period
    4.7          
(8) Derivatives
Interest Rate Swaps
In conjunction with the repayment of its old credit facility in February 2010, the Partnership settled all of its interest rate swaps for total payments of $27.2 million. The balance of $0.6 million in accumulated other comprehensive income related to the interest rate swaps was moved to realized loss as a part of the settlement.
The impact of the interest rate swaps on net income is included in other income (expense) in the consolidated statements of operations as part of interest expense, net, as follows (in thousands):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Change in fair value of derivatives that do not qualify for hedge accounting
  $ 22,405     $ 382  
Realized losses on derivatives
    (26,542 )     (4,556 )
 
           
 
  $ (4,137 )   $ (4,174 )
 
           
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.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
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” and “processing margin 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 swap transactions protect against changes in the value of gas that the Partnership has stored to serve various operational requirements. Basis swaps are used to hedge basis location price risk due to buying gas into one of the Partnership’s systems on one index and selling gas off that same system on a different index. Processing margin financial swaps are used to hedge fractionation spread risk at the Partnership’s processing plants relating to the option to process versus bypassing the Partnership’s equity gas.
The components of (gain) loss on derivatives in the consolidated statements of operations relating to commodity swaps are (in thousands):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Change in fair value of derivatives that do not qualify for hedge accounting
  $ 2,348     $ 524  
Realized (gain) loss on derivatives
    1,408       (5,942 )
Ineffective portion of derivatives qualifying for hedge accounting
    (60 )     (5 )
 
           
Net (gain) loss related to commodity swaps
    3,696       (5,423 )
Net loss included in income from discontinued operations
          1,087  
 
           
(Gain) loss on derivatives included in continuing operations
  $ 3,696     $ (4,336 )
 
           
The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in thousands):
                 
    March 31,     December 31,  
    2010     2009  
Fair value of derivative assets – current, designated
  $ 232     $ 369  
Fair value of derivative assets – current, non-designated
    8,134       8,743  
Fair value of derivative assets – long term, non-designated
    6,168       5,665  
Fair value of derivative liabilities – current, designated
    (1,090 )     (2,536 )
Fair value of derivative liabilities – current, non-designated
    (11,378 )     (9,841 )
Fair value of derivative liabilities – long term, non-designated
    (5,927 )     (5,338 )
 
           
Net fair value of derivatives
  $ (3,861 )   $ (2,938 )
 
           
Set forth below is the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at March 31, 2010 (all gas volumes are expressed in MMBtus and liquids are expressed in gallons). The remaining term of the contracts extend no later than June 2011 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.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
                 
March 31, 2010  
Transaction Type   Volume     Fair Value  
    (In thousands)  
Cash Flow Hedges:*
               
Liquids swaps (short contracts)
    (7,475 )   $ (944 )
Liquids swaps (long contracts)
    494       86  
 
             
Total swaps designated as cash flow hedges
          $ (858 )
 
             
 
               
Mark to Market Derivatives:*
               
Swing swaps (long contracts)
    263     $ (5 )
Physical offsets to swing swap transactions (short contracts)
    ¾       ¾  
Swing swaps (short contracts)
    (3,450 )     (15 )
Physical offsets to swing swap transactions (long contracts)
    3,713       9  
 
               
Basis swaps (long contracts)
    48,011       11,317  
Physical offsets to basis swap transactions (short contracts)
    (3,340 )     11,033  
Basis swaps (short contracts)
    (42,221 )     (9,162 )
Physical offsets to basis swap transactions (long contracts)
    3,340       (12,647 )
 
               
Third-party on-system financial swaps (long contracts)
    36       (153 )
Third-party on-system financial swaps (short contracts)
    (37 )     41  
 
               
Processing margin hedges – liquids (short contracts)
    (12,491 )     (1,631 )
Processing margin hedges – gas (long contracts)
    1,303       (1,893 )
 
               
Storage swap transactions (short contracts)
    (80 )     103  
 
             
Total mark to market derivatives
          $ (3,003 )
 
             
 
     
*   All are gas contracts, volume in MMBtu’s, except for processing margin hedges – liquids and liquids swaps (volume in gallons).
On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. 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 $25.5 million would be reduced to $13.4 million due to the netting feature which all relates to other energy companies.
Impact of Cash Flow Hedges
The impact of realized gain or loss from derivatives designated as cash flow hedge contracts in the consolidated statements of operations is summarized below (in thousands):
                 
    Three Months Ended March 31,  
    2010     2009  
Increase (decrease) in Midstream revenue
               
Natural gas
  $ ¾     $ 488  
Liquids
    (842 )     5,178  
Realized (gain) loss included in income from discontinued operations
    ¾       (356 )
 
           
Realized gain (loss) included in income from continuing operations
  $ (842 )   $ 5,310  
 
           
Natural Gas
As of March 31, 2010, the Partnership has no balances in accumulated other comprehensive income related to natural gas.
Liquids
As of March 31, 2010, an unrealized derivative fair value net loss of $0.9 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss), all of which is expected to be reclassified into earnings through March 2011. 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 statements of operations. The Partnership estimates the fair value of all of its energy trading contracts using actively quoted prices. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):
                                 
    Maturity Periods  
    Less than one year     One to two years     More than two years     Total fair value  
 
March 31, 2010
  $ (3,244 )   $ 241     $ ¾     $ (3,003 )
(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 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
The Partnership’s derivative contracts primarily consist of commodity swaps and interest rate swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs for future interest rates and commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy. 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 market inputs for valuing the Partnership’s interest rate swap contracts are also classified as Level 2 in hierarchy.
Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in thousands):
                 
    March 31,     December 31,  
    2010     2009  
    Level 2     Level 2  
 
               
Interest Rate Swaps
  $ ¾     $ (24,728 )
Commodity Swaps*
    (3,861 )     (2,938 )
 
           
Total
  $ (3,861 )   $ (27,666 )
 
           
 
     
*   Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income at each measurement date.

 

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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).
                                 
    March 31, 2010     December 31, 2009  
    Carrying     Fair     Carrying     Fair  
    Value     Value     Value     Value  
 
Cash and cash equivalents
  $ 6,561     $ 6,561     $ 10,703     $ 10,703  
Trade accounts receivable and accrued revenues
    198,982       198,982       207,655       207,655  
Fair value of derivative assets
    14,534       14,534       14,777       14,777  
Accounts payable, drafts payable and accrued gas purchases
    167,744       167,744       174,008       174,008  
Long-term debt
    766,143       803,709       873,702       872,340  
Obligations under capital lease
    23,246       21,070       23,799       22,399  
Fair value of derivative liabilities
    18,395       18,395       42,443       42,443  
The carrying amounts of the Company’s cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.
The Partnership’s long-term debt included borrowings under revolving credit facilities totaling $38.0 million as of March 31, 2010 and $529.6 million as of December 31, 2009, respectively, and accrued interest under floating interest rate facilities. Accordingly, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the new and old credit facilities. As of March 31, 2010, the Partnership also had borrowings totaling $725.0 million under senior unsecured notes with a fixed rate of 8.875% and a series B secured note with a principal amount of $18.1 million with a fixed rate of 9.5%. As of December 31, 2009 the Partnership also had borrowings totaling $326.0 million under senior secured notes with a weighted average interest rate of 10.5% and a series B secured note with a principal amount of $18.1 million with a fixed rate of 9.5%. The fair value of the senior unsecured notes as of March 31, 2010 was based on third party market quotations. The fair values of the senior secured notes as of December 31, 2009 and the series B secured note as of March 31, 2010 and December 31, 2009 were adjusted to reflect current market interest rate for such borrowings on the applicable date. The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.
(11) Income Tax
The Company has recorded a deferred tax asset in the amount of $20.2 million and $8.0 million relating to the difference between its book and tax basis of its investment in the Partnership as of March 31, 2010 and December 31, 2009, 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 related valuation allowance increased by $12.2 million during the first quarter of 2010 due to the issuance of the Partnership’s Series A preferred units. The income tax provision for the three months ended March 31, 2010 reflects a tax benefit of $2.6 million for current period loss from continuing operations.
Taxes are shown in the statements of operations as follows (in thousands):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Income tax provision (benefit)
  $ (2,585 )   $ 2,041  
Tax provision on discontinued operations
    ¾       484  
 
           
Total tax provision (benefit)
  $ (2,585 )   $ 2,525  
 
           

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
(12) Commitments and Contingencies
(a) Employment Agreements
Certain members of management of the Company are parties to employment contracts with the general partner of the Partnership. The employment agreements provide those senior managers with severance payments in certain circumstances and prohibit each such person from competing with the general partner of the Partnership or its affiliates for a certain period of time following the termination of such person’s employment.
(b) Environmental Issues
The Partnership acquired LIG Pipeline Company and its subsidiaries on April 1, 2004. Contamination from historical operations was identified during due diligence at a number of sites owned by the acquired companies. The seller, AEP, has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third-party company pursuant to which the remediation costs associated with these sites have been assumed by this third party company that specializes in remediation work. The Company does not expect to incur any material liability with these sites; however, there can be no assurance that the third parties who have assumed responsibility for remediation of site conditions will fulfill their obligations. In addition, the Partnership has disclosed possible Clean Air Act monitoring deficiencies it has discovered to the Louisiana Department of Environmental Quality (LDEQ) and is working with the department to correct these deficiencies and to address modifications to facilities to bring them into compliance. The Company does not expect to incur any material environmental liability associated with these issues.
(c) Other
The Company is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.
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. Denbury alleged damages in the amount of $16.2 million, plus interest and attorneys’ fees. Crosstex denied any liability and sought to have the action dismissed. A three-person arbitration panel conducted a hearing on the merits in December 2009. At the close of the evidence at the hearing, the panel granted judgment for Crosstex on one of Denbury’s claims, and on February 16, 2010, the panel granted judgment for Denbury on its remaining claims in the amount of $3.0 million plus interest, attorneys’ fees and costs. The panel will conduct additional proceedings to determine the amount of attorneys’ fees and costs, if any, that should be awarded to Denbury. The Company estimates that the total award will be between $3.0 million and $4.0 million at the conclusion of these additional proceedings. The Company has accrued $3.7 million in other current liabilities for this award as of December 31, 2009 and reflected the related expense in purchased gas costs in the fourth quarter of 2009. This liability remains unsettled at March 31, 2010.
At times, the Partnership’s gas-utility subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain provided under state law. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s gas utility subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.
The Partnership (or its subsidiaries) is defending 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.

 

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CROSSTEX ENERGY, INC.
Notes to Condensed Consolidated Financial Statements — (Continued)
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. During 2008 and 2009, the Partnership fully reserved the unsecured claim of $3.9 million and the receivable was written-off as of December 31, 2009. In April 2010, the Partnership settled with the Estate its $2.3 million administrative claim for $2.1 million. The additional $0.2 million loss was realized as of March 31, 2010.
(13) Subsequent Events
Subsequent to the quarter end March 31, 2010 and prior to issuance of the financial statements, the Partnership sold a non-operational processing plant held in inventory for $19.5 million which approximates the carrying value of the plant. No further events material to the financial statement presentation were noted during this review of subsequent events.

 

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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, treating, 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 25.0% 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 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 in 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 February 2009, the Oklahoma assets were sold; in August 2009 the Alabama, Mississippi and south Texas Midstream assets were sold; in October 2009 the Treating assets were sold; and in January 2010 the east Texas assets were sold. The Partnership’s primary focus for continuing operations is on the gathering, processing, transmission and marketing of natural gas and NGLs, as well as providing certain producer services which constitute one reporting segment of midstream activity. Currently the geographic focus is in the north Texas Barnett shale area and in Louisiana. The Partnership focuses on gross margin to manage its operations because its business is generally to purchase and resell natural gas for a margin, or to gather, process, transport or market natural gas and NGLs for a fee.
The Partnership’s margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities and the volumes of NGLs handled at its fractionation facilities. The Partnership generates revenues from four primary sources:
    purchasing and reselling or transporting natural gas on the pipeline systems it owns;
 
    processing natural gas at its processing plants 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 the Partnership 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. The Partnership attempts to execute all purchases and sales substantially concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction. The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that are under contract may decline due to reduced drilling or other causes and the Partnership may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, the Partnership has certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and it captures the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as its margin. Changes in the basis spread can increase or decrease margins (or even be negative at times). For example, the Partnership is a party to a contract with a term to 2019 to supply approximately 150 MMBtu/d of gas. It buys the gas for this contract on several different production-area indices into its North Texas Pipeline and sells the gas into a different market area index. For the first quarter of 2010, this imbalance resulted in a loss of approximately $0.7 million on this contract due to the basis differentials between the various market prices, which may be more or less in future quarters depending on market conditions.

 

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The Partnership also realizes gross margins from processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fixed-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 the liquids produced with margins higher during periods of relatively high liquids prices. Under fixed-fee based contracts margins are driven by throughput volume. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk.”
Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision and associated transportation and communication costs, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are normally fairly stable across broad volume ranges, and therefore, do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas moved through the asset.
Recent Developments and Business Strategy
During the past 18 months, the Partnership repositioned itself through asset dispositions and by recapitalizing and reorganizing its operations. The Partnership is now well positioned to focus on the performance and growth of its existing assets, to pursue strategic acquisitions and to undertake selective construction and expansion opportunities. During the first quarter of 2010, the Partnership recapitalized its operations with the following transactions:
    Sale of Preferred Units. On January 19, 2010, the Partnership issued approximately $125.0 million of Series A Convertible Preferred Units to an affiliate of Blackstone/GSO Capital Solutions for net proceeds of $120.8 million. Crosstex Energy, GP, L.P. made a general partner contribution of $2.6 million in connection with the issuance to maintain its 2% general partner interest. The 14,705,882 preferred units are convertible by the holders thereof at any time into common units on a one-for-one basis, subject to certain adjustments in the event of certain dilutive issuances of common units. The Partnership has the right to force conversion of the preferred units after three years if (i) the daily volume-weighted average trading price of the common units is greater than 150% of the then-applicable conversion price for 20 out of the trailing 30 days ending on two trading days before the date on which the Partnership delivers notice of such conversion, and (ii) the average daily trading volume of common units must have exceeded 250,000 common units for 20 out of the trailing 30 trading days ending on two trading days before the date on which the Partnership delivers notice of such conversion. The preferred units are not redeemable. They will receive a quarterly distribution that will be the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. Such quarterly distribution may be paid in cash, in additional preferred units issued in kind or any combination thereof, provided that the distribution may not be paid in additional preferred units if the Partnership pays a cash distribution on common units.
 
    Issuance of Senior Unsecured Notes. On February 10, 2010, the Partnership issued $725.0 million in aggregate principal amount of 8.875% senior unsecured notes due 2018 at an issue price of 97.907% to yield 9.25% to maturity, including the original issue discount (OID). Net proceeds from the sale of the notes of $689.7 million (net of transaction costs and OID), together with borrowings under its new credit facility discussed below, were used to repay in full amounts outstanding under its old bank credit facility and senior secured notes and to pay related fees, costs and expenses, including the settlement of interest rate swaps associated with its old credit facility. The notes are unsecured and unconditionally guaranteed on a senior basis by certain of the Partnership’s direct and indirect subsidiaries, including substantially all of its current subsidiaries. Interest payments are due semi-annually in arrears starting in August 2010. The Partnership has the option to redeem all or a portion of the notes at any time on or after February 15, 2014, at the specified redemption prices. Prior to February 15, 2014, the Partnership may redeem the notes, in whole or in part, at a “make-whole” redemption price. In addition, the Partnership may redeem up to 35% of the notes prior to February 15, 2013 with the cash proceeds from certain equity offerings.
 
    New Credit Facility. In February 2010, the Partnership amended and restated its secured bank credit facility with a new secured bank credit facility, which is guaranteed by substantially all of the Partnership’s subsidiaries. The new credit facility has a borrowing capacity of $420.0 million and matures in February 2014. Obligations under the new credit facility are secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors, including all material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of the equity interests in substantially all of the Partnership’s subsidiaries. Under the new credit facility, borrowings bear interest at the Partnership’s option at the British Bankers Association LIBOR Rate plus an applicable margin, or the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate, in each case plus an applicable margin. The Partnership pays a per annum fee on all letters of credit issued under the new credit facility, and pays a commitment fee of 0.50% per annum on the unused availability under the new credit facility. The letter of credit fee and the applicable margins for its interest rate vary quarterly based on the Partnership’s leverage ratio.

 

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The Partnership also completed the sale of its east Texas assets for $40.0 million in January 2010 and recognized a $14.1 million gain on disposition.
Results of Operations
Set forth in the table below is certain financial and operating data for the periods indicated, which excludes financial and operating data for discontinued operations.
                 
    Three Months Ended March 31,  
    2010     2009  
    (Dollars in millions)  
 
Midstream revenues
  $ 432.5     $ 352.4  
Purchased gas
    (353.6 )     (284.2 )
Gas and NGL marketing activities
    2.3       0.7  
 
           
Total gross margin
  $ 81.2     $ 68.9  
 
           
 
               
Midstream Volumes (MMBtu/d):
               
Gathering and transportation.
    1,998,000       2,031,000  
Processing
    1,393,000       1,098,000  
Producer services
    57,000       110,000  
Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009
Gross Margin and Gas and NGL Marketing Activities. Gross margin was $81.2 million for the three months ended March 31, 2010 compared to $68.9 million for the three months ended March 31, 2009, an increase of $12.2 million, or 17.8%. The increase was primarily due to gross margin improvement in the processing business due to a favorable NGL market. Gross margin from gas and NGL marketing activities increased for the comparative periods by approximately $1.6 million primarily due to an improved fee structure and an increase in activity in the liquids marketing business.
The favorable processing environment led to significant gross margin growth for processing plants in Louisiana for the three months ended March 31, 2010 over the same period in 2009. Overall the plants in the region reported a gross margin increase of approximately $9.3 million. The primary contributors to this improvement were the Plaquemine, Gibson and Eunice processing plants which had gross margin increases of $3.4 million, $2.5 million and $1.7 million, respectively. The LIG gathering and transmission system contributed gross margin growth of $4.9 million for the three months ended March 31, 2010, primarily due to improved pricing and higher volumes on the northern part of the system. In addition, the LIG results include a one time adjustment to revenue due to the refund of fees related to the settlement of a rate case on the system. The total financial impact of this adjustment is a reduction in gross margin of $1.2 million. The north Texas region had an overall gross margin decline for the comparable periods of $1.4 million. A throughput volume decrease on the gathering and transmission systems contributed to a gross margin decline of $2.0 million for the three months ended March 31, 2010 over the same period in 2009. This was partially offset by a gross margin increase of $0.6 million on the north Texas processing assets. The east Texas pipeline system and the Arkoma system, which were sold in January 2010 and April 2009, respectively, but not reported in discontinued operations, contributed a total gross margin decline of $2.1 million.
Operating Expenses. Operating expenses were $26.5 million for the three months ended March 31, 2010, compared to $27.9 million for the three months ended March 31, 2009, a decrease of $1.4 million, or 5.1%. The decrease is a result of strategic initiatives undertaken to reduce expenses.
General and Administrative Expenses. General and administrative expenses were $13.5 million for the three months ended March 31, 2010 compared to $14.5 million for the three months ended March 31, 2009, a decrease of $1.0 million, or 7.0%. The decrease is a result of strategic initiatives undertaken to reduce expenses which yielded reductions of $1.6 million and $0.7 million in compensation related costs and utilities and rent, respectively. These reductions were partially offset by increased bad debt of $0.3 million on the SemStream bankruptcy settlement and $0.8 million in professional and consulting fees.

 

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Gain on Sale of Property. Assets sold during the three months ended March 31, 2010 generated a net gain of $14.3 million, resulting primarily from the sale of the east Texas assets.
Gain/Loss on Derivatives. The Partnership had a loss on derivatives of $3.7 million for the three months ended March 31, 2010 compared to a gain of $4.3 million for the three months ended March 31, 2009. The derivative transaction types contributing to the net (gain) loss are as follows (in millions):
                                 
    Three Months Ended March 31,  
    2010     2009  
    Total     Realized     Total     Realized  
(Gain)/Loss on Derivatives:
                               
Basis swaps
  $ 2.1     $ (0.5 )   $ (0.9 )   $ (0.7 )
Processing margin hedges
    1.8       1.9       (4.1 )     (4.1 )
Storage
    (0.1 )           (0.2 )     (1.0 )
Other
    (0.1 )           (0.2 )     (0.2 )
 
                       
Net gains (losses) related to commodity swaps
    3.7       1.4       (5.4 )     (6.0 )
Derivative gains included in income from discontinued operations
                1.1       0.4  
 
                       
 
  $ 3.7     $ 1.4     $ (4.3 )   $ (5.6 )
 
                       
Impairments. Impairment expense was $1.0 million for the three months ended March 31, 2010 and there were no impairments during the three months ended March 31, 2009. The impairment in 2010 relates to expected loss on the sale of pipe in inventory during the second quarter of 2010.
Depreciation and Amortization. Depreciation and amortization expenses were $27.1 million for the three months ended March 31, 2010 compared to $28.8 million for the three months ended March 31, 2009, a decrease of $1.7 million, or 5.8%, resulting primarily from the decision made in the fourth quarter of 2009 to extend the depreciable lives on processing plants.
Interest Expense. Interest expense was $26.9 million for the three months ended March 31, 2010 compared to $17.5 million for the three months ended March 31, 2009, an increase of $9.3 million, or 53.2%. The increase in interest expense between periods was primarily due to increased borrowing rates on the facilities between periods and additional expense totaling $1.6 million associated with make-whole interest payments and the write-off of debt issue costs for the January repayment of debt with proceeds from the preferred unit sale and the east Texas asset sale. The Partnership’s borrowing rates are higher in 2010 due to the late February 2009 amendments to the old credit facility and senior secured notes which were repaid in full in mid-February 2010 with proceeds from the issuance of the $725.0 million senior unsecured notes. Net interest expense consists of the following (in millions):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Senior notes (secured and unsecured)
  $ 12.8     $ 6.1  
PIK interest on senior secured notes
    1.4       0.4  
Bank credit facility
    3.8       4.2  
Mark to market interest rate swaps
    (22.4 )     (0.4 )
Realized interest rate swaps
    26.5       4.6  
Amortization of debt issue cost
    2.1       1.5  
Other
    2.7       1.1  
 
           
Total
  $ 26.9     $ 17.5  
 
           
Loss on Extinguishment of Debt. The Partnership recognized a loss on extinguishment of debt during the three months ended March 31, 2010 and 2009 of $14.7 million and $4.7 million, respectively. In February 2010, the Partnership repaid its existing credit facility and senior secured notes which resulted in make-whole interest payments on the senior secured notes and the write-off of unamortized debt costs totaling $14.7 million. The loss of $4.7 million on extinguishment of debt incurred in the three months ended March 31, 2009 related to the amendment of the old credit facility and senior secured notes.
Income Taxes. Income tax benefit was $2.6 million for the three months ended March 31, 2010 compared to a tax expense of $2.0 million for the three months ended March 31, 2009. The income tax provision for the three months ended March 31, 2010 reflects a net tax benefit of $2.6 million for the current period loss. The income tax provision for the three months ended March 31, 2009 reflects a tax benefit of $2.2 million for current period loss offset by a $4.6 million income tax expense attributable to a tax basis adjustment in the Partnership related to the conversion of the senior subordinated series D units to common units on March 23, 2009.

 

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Interest of Non-Controlling Partners in the Partnership’s Net Loss from Continuing Operations. The interest of non-controlling partners in the Partnership’s net loss was $9.6 million for the three months ended March 31, 2010 compared to a loss of $11.6 million for the three months ended March 31, 2009 due to the changes shown in the following summary (in millions):
                 
    For the Three Months Ended  
    March 31,  
    2010     2009  
Net loss for the Partnership from continuing operations
  $ (17.4 )   $ (19.1 )
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors
    1.1       0.6  
Loss allocation to CEI for its 2% general partner share of Partnership loss
    0.4       0.4  
 
           
Net loss from continuing operations allocable to limited partners
    (15.9 )     (18.1 )
Less: CEI’s share of net loss allocable to limited partners
    (6.3 )     (6.5 )
 
           
Non-controlling partners’ share of Partnership net loss from continuing operations
  $ (9.6 )   $ (11.6 )
 
           
Discontinued Operations. During 2009 the Partnership sold certain non-strategic assets. In accordance with FASB ASC 360-10-05-4 the results of operations related to the assets sold are presented in income from discontinued operations for the three months ended March 31, 2009 in the statements of operations. Revenues, the related costs of operations, depreciation and amortization, and allocated interest are reflected in the income from discontinued operations. No 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  
    March 31, 2009  
Midstream revenues
  $ 179.2  
Treating revenues
  $ 16.3  
Net income from discontinued operations net of tax
  $ 3.3  
Gathering and Transmission Volumes (MMBtu/d)
    574,000  
Processing Volumes (MMBtu/d)
    194,000  
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, 2009.
Liquidity and Capital Resources
Cash Flows from Operating Activities. Net cash used in operating activities was $25.3 million for the three months ended March 31, 2010 compared to net cash provided by operations of $10.0 million for the three months ended March 31, 2009. Income before non-cash income and expenses and changes in working capital for comparative periods were as follows (in millions):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Income before non-cash income and expenses
  $ (27.6 )   $ 25.6  
Changes in working capital
    2.3       (15.5 )
The primary reason for the decrease in cash flow from income before non-cash income and expenses of $53.2 million from 2009 to 2010 relates to interest payments for settlements of interest rate swaps, make-whole payments, and PIK notes.

 

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Cash Flows from Investing Activities. Net cash provided from investing activities was $30.9 million for the three months ended March 31, 2010 and net cash used in investing activities was $34.6 million for the three months ended March 31, 2009. The primary investing outflows were capital expenditures, net of accrued amounts, as follows (in millions):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Growth capital expenditures
  $ 7.5     $ 46.6  
Maintenance capital expenditures
    2.2       2.1  
 
           
Total
  $ 9.7     $ 48.7  
 
           
Cash flows from investing activities for the three months ended March 31, 2010 and 2009 also include proceeds from property sales of $39.7 million and $11.0 million, respectively. The east Texas asset were sold in the quarter ending March 31, 2010 for $40.0 million. The Arkoma asset was sold in the quarter ending March 31, 2009 for $11.0 million.
Cash Flows from Financing Activities. Net cash used by financing activities was $9.7 million and net cash provided by financing was $24.6 million for the three months ended March 31, 2010 and 2009, respectively. Financing activities during 2010 primarily relate to the issuance of senior unsecured notes during 2009, sale of preferred units and establishment of a new credit facility and repaying the Partnership’s prior credit facility and senior secured notes. Financing activities primarily relate to funding of capital expenditures. The Partnership’s financings have primarily consisted of borrowings and repayments under the old and new bank credit facilities, borrowings and repayments under capital lease obligations, senior secured note repayments, senior unsecured note borrowings and debt refinancing costs during 2010 and 2009 as follows (in millions):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Net borrowings (repayments) under bank credit facilities
  $ (491.6 )   $ 73.0  
Senior secured note repayments
    (316.5 )     (2.4 )
Senior unsecured note borrowings (net of discount on the note)
    709.8        
Net borrowings (repayments) under capital lease obligations
    (0.6 )     0.9  
Debt refinancing costs
    (28.1 )     (13.4 )
Historically dividends to shareholders and distributions to non-controlling partners in the Partnership represented our primary use of cash in financing activities. We ceased making dividends to our shareholders and the Partnership ceased making distributions to its unitholders in the first quarter of 2009 due to liquidity issues and because the terms of the Partnership’s old credit facility and senior secured note agreement restricted its ability to make distributions unless certain conditions were met. No dividends or cash distributions were paid during the three months ended March 31, 2010. Total cash distributions made during the three months ended March 31, 2009 were as follows (in millions):
         
    Three Months Ended  
    March 31, 2009  
Dividend to shareholders
  $ 4.2  
Non-controlling partner distributions
    7.5  
 
     
Total
  $ 11.7  
 
     
Although the Partnership’s new credit facility does not limit its ability to make distributions as long as the Partnership is not in default of such facility (and the indenture governing the Partnership’s senior unsecured notes only requires it to meet a minimum fixed charge coverage ratio test in order to make distributions), any decision to make cash distributions on its units and the amount of any such distributions will consider maintaining sufficient cash flow in excess of the distribution to continue to move towards lower leverage ratios. The Partnership has established a target over the next couple of years of achieving a ratio of total debt to Adjusted EBITDA (earnings before interest, income taxes, depreciation and amortization, impairments, non-cash mark-to-market items and other miscellaneous non-cash items) of less than 4.0 to 1.0, and the Partnership does not currently expect to make cash distributions on outstanding units unless such ratio is less than 4.5 to 1.0 (pro forma for any distribution). The Partnership will also consider general economic conditions and its outlook for business as it determines to pay any distribution. We will not resume dividends to shareholders until the Partnership resumes cash distributions to us.
In May 2010, the Partnership declared a cash distribution on its preferred units of $0.2125 per unit for a total $3.1 million payable in May 2010. As described under “Recent Developments and Business Strategy — Sale of Preferred Units” above, the quarterly distributions on preferred units may be paid in cash, in additional preferred units issued in kind or any combination thereof at the Partnership’s discretion. The distribution payment in cash to the preferred units was in compliance with the Partnership’s financial guidelines of achieving a ratio of debt to Adjusted EBITDA of less than 4.5 to 1.0 on a pro forma basis before making cash distributions.

 

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In order to reduce our interest costs, the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on the Partnership’s revolving credit facility. The Partnership borrows money under its $420.0 million new credit facility to fund checks as they are presented. As of March 31, 2010, the Partnership had approximately $232.5 million of available borrowing capacity under this facility. Changes in drafts payable for the three months ended 2010 and 2009 were as follows (in millions):
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Decrease in drafts payable
  $ 1.6     $ 21.5  
Working Capital Deficit. We had a working capital deficit of $4.8 million as of March 31, 2010 primarily due to a net liability for the fair value of derivatives of $4.1 million and drafts payable of $3.6 million. The fair value of derivatives reflects the mark to market of commodity derivatives. As discussed under “Cash Flows from Financing Activities” above, in order to reduce interest costs the Partnership does not borrow money to fund outstanding checks until they are presented to the bank.
Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of March 31, 2010.
Capital Requirements of the Partnership. The Partnership’s 2010 capital budget includes approximately $25.0 million of identified growth projects. Although the Partnership expects to identify more growth projects during 2010 in addition to projects currently budgeted, it does not anticipate that capital expenditures during 2010 will exceed $100.0 million. During the first quarter of 2010, growth capital investments were $7.5 million which were funded by internally generated cash flow.
Total Contractual Cash Obligations. A summary of the Partnership’s total contractual cash obligations as of March 31, 2010, is as follows (in millions):
                                                         
    Payments Due by Period  
    Total     2010     2011     2012     2013     2014     Thereafter  
 
Long-term debt
  $ 781.1     $ 11.0     $ 7.1     $     $     $ 38.0     $ 725.0  
Interest payable on fixed long-term debt obligations
    509.3       33.8       63.8       63.5       63.5       63.5       221.2  
Capital lease obligations
    27.2       2.4       3.0       ` 3.0       3.0       3.0       12.8  
Operating leases
    51.2       9.0       12.4       9.6       6.4       4.9       8.9  
Uncertain tax position obligations
    3.3       3.3                                
 
                                         
Total contractual obligations
  $ 1,372.1     $ 59.5     $ 86.3     $ 76.1     $ 72.9     $ 109.4     $ 967.9  
 
                                         
The above table does not include any physical or financial contract purchase commitments for natural gas.
Indebtedness
As of March 31, 2010 and December 31, 2009, long-term debt consisted of the following (in thousands):
                 
    March 31,     December 31,  
    2010     2009  
Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rate (per the facility) at December 31, 2009 was 6.75%
  $     $ 529,614  
New credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rate (per the new facility) at March 31, 2010 was 4.66%
    38,000        
Senior secured notes (including PIK notes (1) of $9.5 million), weighted average interest rate at December 31, 2009 was 10.5%
          326,034  
Senior unsecured notes, net of discount of $14,911 which bear interest at the rate of 8.875%,
    710,089        
Series B secured note assumed in the Eunice transaction, which bears interest at the rate of 9.5%
    18,054       18,054  
 
           
 
    766,143       873,702  
Less current portion
    (10,995 )     (28,602 )
 
           
Debt classified as long-term
  $ 755,148     $ 845,100  
 
           
     
(1)   The senior secured notes began accruing additional interest of 1.25% per annum in February 2009 (the “PIK notes”) in the form of an increase in the principal amounts unless the leverage ratio is less than 4.25 to 1.00 at the end of any fiscal quarter. These notes were paid in full in February 2010.

 

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New Credit Facility. As of March 31, 2010, the Partnership had a new bank credit facility with a borrowing capacity of $420.0 million that matures in February 2014. As of March 31, 2010, $187.5 million was outstanding under the new bank credit facility, including $149.5 million of letters of credit, leaving approximately $232.5 million available for future borrowing. The new bank credit facility is guaranteed by substantially all of the Partnership’s subsidiaries.
Recent Accounting Pronouncements
In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-06, Improving Disclosures about Fair Value Measurements, which amends FASB ASC Topic 820, Fair Value Measurements and Disclosures. The ASU requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information about purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. The ASU also clarifies existing fair-value measurement disclosure guidance about the level of disaggregation, inputs, and valuation techniques. We have evaluated the ASU and determined that we are not currently impacted by the update.
Disclosure Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, 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, 2009, 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.
Interest Rate Risk
The Partnership is exposed to interest rate risk on its variable rate new bank credit facility. At March 31, 2010, the new bank credit facility had outstanding borrowings of $38.0 million which approximated fair value. Based on the amount outstanding on its new bank credit facility as of March 31, 2010, the Partnership estimates that a 1% increase or decrease in the interest rate would change its annual interest expense by approximately $0.4 million.
At March 31, 2010, the Partnership had total fixed rate debt obligations of $743.1 million, consisting of its senior unsecured notes with an interest rate of 8.875% and a series B secured note with an interest rate of 9.5%. The fair value of these fixed rate obligations was approximately $765.7 million as of March 31, 2010. 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 unsecured notes) by $33.7 million based on the debt obligations as of March 31, 2010.

 

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Commodity Price Risk
The Partnership is subject to significant risks due to fluctuations in commodity prices. Its exposure to these risks is primarily in the gas processing component of its business. The Partnership currently processes gas under three main types of contractual arrangements:
  1.   Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR. The Partnership’s margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership mitigates its risk of processing natural gas when margins would be negative primarily through its ability to bypass processing when it is not profitable for the Partnership, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.
 
  2.   Percent of liquids contracts: Under these contracts, the Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, its margins from these contracts are greater during periods of high liquids prices. The Partnership’s margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.
 
  3.   Fee based contracts: Under these contracts the Partnership has no commodity price exposure, and is paid a fixed fee per unit of volume that is processed.
The gross margin presentation in the table below is calculated net of results from discontinued operations. Gas processing margins by contract types and gathering and transportation margins as a percent of total gross margin for the comparative year-to-date periods are as follows:
                 
    Three Months Ended  
    March 31,  
    2010     2009  
Gathering and transportation margin
    60.2 %     69.0 %
 
               
Gas processing margins:
               
Processing margin
    13.4 %     4.6 %
Percent of liquids
    13.7 %     15.5 %
Fee based
    12.7 %     10.9 %
 
           
Total gas processing
    39.8 %     31.0 %
 
           
 
               
Total
    100.0 %     100.0 %
 
           
The Partnership has hedges in place at March 31, 2010 covering a portion of the liquids volumes it expects to receive under percent of liquids (POL) contracts as set forth in the following table. The relevant payment index price is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).
                                     
                The     The   Fair Value  
        Notional   Partnership     Partnership   Asset/(Liability)  
Period   Underlying   Volume   Pays     Receives*   (In thousands)  
April 2010-September 2010
  Ethane   46 (MBbls)   Index   $0.6418/gal   $ 147  
April 2010-December 2010
  Propane   79 (MBbls)   Index   $0.9597/gal     (561 )
April 2010-December 2010
  Normal Butane   26 (MBbls)   Index   $1.2597/gal     (227 )
April 2010-December 2010
  Natural Gasoline   13 (MBbls)   Index   $1.4655/gal     (213 )
 
                                 
 
                              $ (854 )
 
                                 
     
*   weighted average

 

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                The     The    
        Notional   Partnership     Partnership   Fair Value  
Period   Underlying   Volume   Pays     Receives*   Asset/(Liability)  
                      (In thousands)  
January 2011-March 2011
  Natural Gasoline   2 (MBbls)   Index   $1.8075/gal   $ (4 )
 
                                 
 
                              $ (4 )
 
                                 
     
*   weighted average
The Partnership has hedged its exposure to declines in prices for NGL volumes produced for our 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 has hedged 51.9% of its hedgeable volumes at risk through December of 2010 (21.3% of total volumes at risk through December of 2010). The Partnership has begun hedging its POL exposure for 2011 as set forth above.
The Partnership also has hedges in place at March 31, 2010 covering the fractionation spread risk related to its processing margin contracts as set forth in the following table:
                                     
                The   The      
        Notional   Partnership   Partnership   Fair Value  
Period   Underlying   Volume   Pays   Receives*   Asset/(Liability)  
April 2010-December 2010
  Ethane   138 (MBbls)   Index   $0.5191/gal*   $ (241 )
April 2010-December 2010
  Propane   58 (MBbls)   Index   $0.9359/gal*     (466 )
April 2010-December 2010
  Normal Butane   39 (MBbls)   Index   $1.2241/gal*     (401 )
April 2010-December 2010
  Natural Gasoline   38 (MBbls)   Index   $1.5533/gal*     (474 )
April 2010-December 2010
  Natural Gas   1,174 (MMbtu/d)   $5.8411/MMBtu*   Index     (1,883 )
 
                                 
 
                              $ (3,465 )
 
                                 
     
*   weighted average
                                     
                The   The      
        Notional   Partnership   Partnership   Fair Value  
Period   Underlying   Volume   Pays   Receives*   Asset/(Liability)  
January 2011 – June 2011
  Propane   12 (MBbls   Index   $1.0660/gal*   $ (23 )
January 2011 – June 2011
  Iso Butane   4 (MBbls)   Index   $1.4737/gal*     (5 )
January 2011 – June 2011
  Normal Butane   4 (MBbls)   Index   $1.4192/gal*     (5 )
January 2011 – June 2011
  Natural Gasoline   5 (MBbls   Index   $1.7623/gal*     (16 )
January 2011 – June 2011
  Natural Gas   129 (MMbtu/d))   $5.3181/MMBtu*   Index     (10 )
 
                                 
 
                              $ (59 )
 
                                 
     
*   weighted average
In relation to its fractionation spread risk, as set forth above, the Partnership has hedged 55.0% of its hedgeable liquids volumes at risk through December 2010 (24.0% of total liquids volumes at risk) and 56.2% of the related hedgeable PTR volumes through December 2010 (23.7% of total PTR volumes). The Partnership has begun hedging its fractionation spread risk for 2011 as set forth above.
The Partnership is also subject to price risk to a lesser extent for fluctuations in natural gas prices with respect to a portion of its gathering and transport services. Approximately 10% of the natural gas the Partnership markets is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price.
Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves it with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.
The Partnership’s primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a risk management committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by its risk management committee.
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.

 

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As of March 31, 2010, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $3.9 million. The aggregate effect of a hypothetical 10% increase in gas and NGLs prices would result in an increase of approximately $1.4 million in the net fair value liability of these contracts as of March 31, 2010.
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, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2010 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 March 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II—OTHER INFORMATION
Item 1. Legal Proceedings
We are involved in various litigation and administrative proceedings arising in the normal course of businesss. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position or results of operations
For a discussion of certain litigation and similar proceedings, please refer to Note 12, “Commitments and Contingencies,” of the Notes to Condensed Consolidated Financial Statements, which is incorporated by reference herein.
Item 1A. Risk Factors
Information about risk factors for the three months ended March 31, 2010, 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, 2009.
Item 6. Exhibits
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
             
Number       Description
  3.1      
Amended and Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006).
  3.2      
Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated March 22, 2006, filed with the Commission on March 28, 2006).
  3.3      
Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.4      
Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s current report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).

 

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Number       Description
  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      
Amendment No. 3 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of January 19, 2010 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010).
  3.8      
Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.9      
Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, file No. 0-50067).
  3.10      
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).
  3.11      
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).
  3.12      
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).
  3.13      
Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
  3.14      
Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of January 19, 2010 (incorporated by reference to Exhibit 3.2 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010).
  4.1      
Indenture, dated as of February 10, 2010, by and among the Registrant, Crosstex Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated February 10, 2010, filed with the Commission on February 16, 2010).
  10.1      
Board Representation Agreement, dated as of January 19, 2010, by and among Crosstex Energy GP, LLC, Crosstex Energy GP, L.P., Crosstex Energy, L.P., Crosstex Energy, Inc. and GSO Crosstex Holdings LLC (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010).
  10.2      
Purchase Agreement, dated as of February 3, 2010, by and among Crosstex Energy, L.P., Crosstex Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated February 3, 2010, filed with the Commission on February 5, 2010).
  10.3      
Amended and Restated Credit Agreement, dated as of February 10, 2010, by and among Crosstex Energy, L.P., Bank of America, N.A., as Administrative Agent and L/C Issuer thereunder, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated February 10, 2010, filed with the Commission on February 16, 2010).
  10.4      
Registration Rights Agreement, dated as of January 19, 2010, by and among Crosstex Energy, L.P. and GSO Crosstex Holdings LLC (incorporated by reference to Exhibit 4.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated January 19, 2010, filed with the Commission on January 22, 2010).
  10.5      
Registration Rights Agreement, dated as of February 10, 2010, by and among Crosstex Energy, L.P., Crosstex Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated February 10, 2010, filed with the Commission on February 16, 2010).
  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.

 

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  CROSSTEX ENERGY, INC.
 
 
  By:   /s/ WILLIAM W. DAVIS    
    William W. Davis,   
May 7, 2010    Executive Vice President and Chief Financial Officer  

 

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