Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

or

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware   30-0108820
(state or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)

3738 Oak Lawn Avenue, Dallas, Texas 75219

(Address of principal executive offices) (zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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

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

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.

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

At August 2, 2011, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P. 222,972,708 Common Units

 

 

 


Table of Contents

FORM 10-Q

INDEX

Energy Transfer Equity, L.P. and Subsidiaries

 

PART I — FINANCIAL INFORMATION

  

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

  

Consolidated Balance Sheets – June 30, 2011 and December 31, 2010

     1   

Consolidated Statements of Operations – Three and Six Months Ended June 30, 2011 and 2010

     3   

Consolidated Statements of Comprehensive Income (Loss) – Three and Six Months Ended June  30, 2011 and 2010

     4   

Consolidated Statement of Equity – Six Months Ended June 30, 2011

     5   

Consolidated Statements of Cash Flows – Six Months Ended June 30, 2011 and 2010

     6   

Notes to Consolidated Financial Statements

     7   

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     38   

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     52   

ITEM 4. CONTROLS AND PROCEDURES

     55   

PART II — OTHER INFORMATION

  

ITEM 1. LEGAL PROCEEDINGS

     55   

ITEM 1A. RISK FACTORS

     56   

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

     58   

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     58   

ITEM 4. [RESERVED]

  

ITEM 5. OTHER INFORMATION

     58   

ITEM 6. EXHIBITS

     58   

SIGNATURE

     62   

 

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Table of Contents

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity,” the “Partnership” or “ETE”) in periodic press releases and some oral statements of Energy Transfer Equity officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part II — Other Information – Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q as well as “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (“SEC”) on February 28, 2011.

Definitions

The following is a list of certain acronyms and terms generally used throughout this document:

 

/d

   per day

Bbls

   barrels

Btu

   British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used

Capacity

   capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

Mcf

   thousand cubic feet

MMBtu

   million British thermal units

MMcf

   million cubic feet

Bcf

   billion cubic feet

NGL

   natural gas liquid, such as propane, butane and natural gasoline

Tcf

   trillion cubic feet

LIBOR

   London Interbank Offered Rate

NYMEX

   New York Mercantile Exchange

Reservoir

   a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs

WTI

   West Texas Intermediate Crude

 

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Table of Contents

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

     June 30,
2011
    December 31,
2010
 
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 148,471      $ 86,264   

Marketable securities

     1,996        2,032   

Accounts receivable, net of allowance for doubtful accounts of $6,908 and $6,706 as of June 30, 2011 and December 31, 2010, respectively

     642,928        612,357   

Accounts receivable from related companies

     82,510        76,331   

Inventories

     348,177        366,384   

Exchanges receivable

     19,451        21,926   

Price risk management assets

     13,104        16,357   

Other current assets

     142,334        109,359   
                

Total current assets

     1,398,971        1,291,010   

PROPERTY, PLANT AND EQUIPMENT

     15,461,476        13,284,430   

ACCUMULATED DEPRECIATION

     (1,687,004     (1,431,698
                
     13,774,472        11,852,732   

ADVANCES TO AND INVESTMENTS IN AFFILIATES

     1,350,627        1,359,979   

LONG-TERM PRICE RISK MANAGEMENT ASSETS

     7,468        13,971   

GOODWILL

     2,008,896        1,600,611   

INTANGIBLES AND OTHER ASSETS, net

     1,325,724        1,260,427   
                

Total assets

   $ 19,866,158      $ 17,378,730   
                

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

     June 30,
2011
    December 31,
2010
 
LIABILITIES AND EQUITY     

CURRENT LIABILITIES:

    

Accounts payable

   $ 451,795      $ 421,556   

Accounts payable to related companies

     14,885        27,351   

Accrued distributions to ETE partners

     139,790          

Exchanges payable

     19,461        16,003   

Price risk management liabilities

     20,729        13,172   

Accrued and other current liabilities

     589,762        567,688   

Current maturities of long-term debt

     22,998        35,305   
  

 

 

   

 

 

 

Total current liabilities

     1,259,420        1,081,075   

LONG-TERM DEBT, less current maturities

     11,123,820        9,346,067   

SERIES A CONVERTIBLE PREFERRED UNITS (Note 10)

     334,170        317,600   

LONG-TERM PRICE RISK MANAGEMENT LIABILITIES

     60,934        79,465   

OTHER NON-CURRENT LIABILITIES

     252,892        235,848   

COMMITMENTS AND CONTINGENCIES (Note 14)

    

PREFERRED UNITS OF SUBSIDIARY (Note 10)

     71,040        70,943   

EQUITY:

    

General Partner

     88        520   

Limited Partners:

    

Common Unitholders

     (23,273     115,350   

Accumulated other comprehensive income (loss)

     (356     4,798   
  

 

 

   

 

 

 

Total partners’ capital (deficit)

     (23,541     120,668   

Noncontrolling interest

     6,787,423        6,127,064   
  

 

 

   

 

 

 

Total equity

     6,763,882        6,247,732   
  

 

 

   

 

 

 

Total liabilities and equity

   $ 19,866,158      $ 17,378,730   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2011     2010     2011     2010  

REVENUES:

        

Natural gas operations

   $ 1,728,951      $ 1,140,768      $ 3,157,908      $ 2,447,477   

Retail propane

     220,296        197,147        748,762        730,586   

Other

     25,659        24,613        57,356        56,446   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     1,974,906        1,362,528        3,964,026        3,234,509   
  

 

 

   

 

 

   

 

 

   

 

 

 

COSTS AND EXPENSES:

        

Cost of products sold — natural gas operations

     1,122,857        723,835        2,006,626        1,636,441   

Cost of products sold — retail propane

     134,728        110,282        445,592        415,263   

Cost of products sold — other

     6,567        6,336        13,360        13,614   

Operating expenses

     222,717        179,745        443,413        350,493   

Depreciation and amortization

     148,530        98,035        287,786        184,366   

Selling, general and administrative

     78,946        65,038        142,445        116,147   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     1,714,345        1,183,271        3,339,222        2,716,324   
  

 

 

   

 

 

   

 

 

   

 

 

 

OPERATING INCOME

     260,561        179,257        624,804        518,185   

OTHER INCOME (EXPENSE):

        

Interest expense, net of interest capitalized

     (181,517     (129,036     (349,446     (250,707

Equity in earnings of affiliates

     28,819        12,193        54,260        18,374   

(Losses) gains on disposal of assets

     (681     1,375        (2,435     (489

Gains (losses) on non-hedged interest rate derivatives

     1,883        (22,468     3,403        (36,892

Impairment of investment in affiliate

            (52,620            (52,620

Other, net

     2,811        (5,213     (9,715     (3,070
  

 

 

   

 

 

   

 

 

   

 

 

 

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE

     111,876        (16,512     320,871        192,781   

Income tax expense

     5,224        4,053        15,127        9,264   
  

 

 

   

 

 

   

 

 

   

 

 

 

INCOME (LOSS) FROM CONTINUING OPERATIONS

     106,652        (20,565     305,744        183,517   

Income from discontinued operations

            86               86   
  

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS)

     106,652        (20,479     305,744        183,603   

LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST

     40,367        (39,747     150,819        51,558   
  

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO PARTNERS

     66,285        19,268        154,925        132,045   

GENERAL PARTNER’S INTEREST IN NET INCOME

     205        60        479        409   
  

 

 

   

 

 

   

 

 

   

 

 

 

LIMITED PARTNERS’ INTEREST IN NET INCOME

   $ 66,080      $ 19,208      $ 154,446      $ 131,636   
  

 

 

   

 

 

   

 

 

   

 

 

 

BASIC NET INCOME PER LIMITED PARTNER UNIT

   $ 0.30      $ 0.09      $ 0.69      $ 0.59   
  

 

 

   

 

 

   

 

 

   

 

 

 

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING

     222,972,708        222,941,172        222,963,741        222,941,140   
  

 

 

   

 

 

   

 

 

   

 

 

 

DILUTED NET INCOME PER LIMITED PARTNER UNIT

   $ 0.30      $ 0.09      $ 0.69      $ 0.59   
  

 

 

   

 

 

   

 

 

   

 

 

 

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING

     222,972,708        222,941,172        222,963,741        222,941,140   
  

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2011     2010     2011     2010  

Net income (loss)

   $ 106,652      $ (20,479   $ 305,744      $ 183,603   

Other comprehensive income (loss), net of tax:

        

Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges

     123        1,725        (13,416     2,555   

Change in value of derivative instruments accounted for as cash flow hedges

     3,829        (19,303     (7,009     4,500   

Change in value of available-for-sale securities

     (643     (724     (35     (3,053
                                
     3,309        (18,302     (20,460     4,002   
                                

Comprehensive income (loss)

     109,961        (38,781     285,284        187,605   

Less: Comprehensive income (loss) attributable to noncontrolling interest

     43,250        (50,410     135,513        57,718   
                                

Comprehensive income attributable to partners

   $ 66,711      $ 11,629      $ 149,771      $ 129,887   
                                

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE SIX MONTHS ENDED JUNE 30, 2011

(Dollars in thousands)

(unaudited)

 

     General
    Partner    
    Common
    Unitholders    
    Accumulated
Other
Comprehensive
Income (Loss)
    Noncontrolling
Interest
        Total      

Balance, December 31, 2010

   $ 520      $ 115,350      $ 4,798      $ 6,127,064      $ 6,247,732   

Distributions to ETE partners

     (1,194     (384,612                   (385,806

Subsidiary distributions

                          (376,440     (376,440

Subsidiary units issued for cash

     285        91,789               882,030        974,104   

Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings

            549               21,684        22,233   

Non-cash executive compensation

            13               612        625   

Other, net

     (2     (808            (3,040     (3,850

Other comprehensive loss, net of tax

                   (5,154     (15,306     (20,460

Net income

     479        154,446               150,819        305,744   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, June 30, 2011

   $ 88      $ (23,273   $ (356   $ 6,787,423      $ 6,763,882   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

 

         Six Months Ended June 30,      
     2011     2010  

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:

    

Net income

   $ 305,744      $ 183,603   

Reconciliation of net income to net cash provided by operating activities:

    

Impairment of investment in affiliate

            52,620   

Proceeds from termination of interest rate derivatives

            15,395   

Depreciation and amortization

     287,786        184,366   

Amortization of finance costs charged to interest

     9,577        6,311   

Non-cash unit-based compensation expense

     22,460        15,194   

Non-cash executive compensation expense

     625        625   

Losses on disposal of assets

     2,435        489   

Distributions in excess of equity in earnings of affiliates, net

     29,875        12,257   

Other non-cash

     18,634        (5,241

Changes in operating assets and liabilities, net of effects of acquisitions (Note 4)

     21,201        336,317   
  

 

 

   

 

 

 

Net cash provided by operating activities

     698,337        801,936   
  

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Cash paid for acquisitions, net of cash received

     (1,948,612     (129,390

Capital expenditures (excluding allowance for equity funds used during construction)

     (794,151     (629,372

Contributions in aid of construction costs

     13,967        7,957   

Advances to affiliates, net

     (22,668     (44,518

Proceeds from the sale of assets

     6,925        9,138   
  

 

 

   

 

 

 

Net cash used in investing activities

     (2,744,539     (786,185
  

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from borrowings

     5,202,535        338,017   

Principal payments on debt

     (3,420,348     (434,250

Subsidiary equity offering, net of issue costs

     974,104        574,522   

Distributions to partners

     (246,016     (241,523

Debt issuance costs

     (22,198     (5,978

Distributions to noncontrolling interests

     (376,440     (230,605

Other

     (3,228       
  

 

 

   

 

 

 

Net cash provided by financing activities

     2,108,409        183   
  

 

 

   

 

 

 

INCREASE IN CASH AND CASH EQUIVALENTS

     62,207        15,934   

CASH AND CASH EQUIVALENTS, beginning of period

     86,264        68,315   
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS, end of period

   $ 148,471      $ 84,249   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar amounts, except per unit data, are in thousands)

(unaudited)

 

1. OPERATIONS AND ORGANIZATION:

Energy Transfer Equity, L.P. (together with its subsidiaries, the “Partnership,” “we,” or “ETE”) is a publicly traded Delaware limited partnership that directly and indirectly owns equity interests in Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”), both publicly traded master limited partnerships engaged in strategic diversified energy-related services.

At June 30, 2011, our equity interests consisted of:

 

     General Partner
Interest
(as a % of total
partnership  interest)
    Incentive
Distribution
Rights
(“IDRs”)
    Common
Units
 

ETP

     1.6     100     50,226,967   

Regency

     1.9     100     26,266,791   

The unaudited consolidated financial statements of ETE presented herein for the three and six month periods ended June 30, 2011 and 2010 include the results of operations of:

 

   

the Parent Company;

 

   

our controlled subsidiaries, ETP and Regency (see description of their respective operations below under “Business Operations”);

 

   

ETP’s and Regency’s wholly-owned subsidiaries; and

 

   

our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Regency.

ETE obtained control of Regency on May 26, 2010, and as such, the three and six month periods ended June 30, 2010 include the results of Regency for the period from the acquisition date through the end of the respective periods.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, Energy Transfer Partners GP, L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency, Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

Business Operations

The Parent Company’s principal sources of cash flow are its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements, distributions to its partners and holders of the Series A Convertible Preferred Units (the “Preferred Units”) and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to fully understand the financial condition of the Parent Company on a stand-alone basis, see Note 19 for stand-alone financial information apart from that of the consolidated partnership information included herein.

The following is a brief description of ETP’s and Regency’s operations:

 

   

ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arkansas, Arizona, Colorado, Louisiana, Mississippi, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas. ETP also holds a 70% interest in a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. ETP is also one of the three largest retail marketers of propane in the United States.

 

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Regency is a publicly traded Delaware limited partnership formed in 2005 engaged in the gathering, treating, processing, compressing and transportation of natural gas and NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas production regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville and Marcellus shales as well as the Permian Delaware basin. Its assets are primarily located in Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets in Texas, Louisiana and Mississippi.

Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2010, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership, as of June 30, 2011 and for the three and six month periods ended June 30, 2011 and 2010, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities of the Partnership’s subsidiaries and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting. Management has evaluated subsequent events through the date the financial statements were issued.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of June 30, 2011, and the Partnership’s results of operations and cash flows for the three and six months ended June 30, 2011 and 2010. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010, as filed with the SEC on February 28, 2011.

Certain prior period amounts have been reclassified to conform to the 2011 presentation. These reclassifications had no impact on net income or total equity.

 

2. ESTIMATES:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for natural gas and NGL related operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

 

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3. ACQUISITION:

LDH Acquisition

On May 2, 2011, ETP-Regency Midstream Holdings, LLC (“ETP-Regency LLC”), a joint venture owned 70% by ETP and 30% by Regency, acquired all of the membership interest in LDH Energy Asset Holdings LLC (“LDH”), from Louis Dreyfus Highbridge Energy LLC (“Louis Dreyfus”) for approximately $1.97 billion in cash (the “LDH Acquisition”). The cash purchase price paid at closing is subject to post-closing adjustments. ETP contributed approximately $1.38 billion to ETP-Regency LLC upon closing to fund its 70% share of the purchase price, while Regency contributed approximately $591.7 million to fund its 30% share of the purchase price. Subsequent to closing, ETP-Regency LLC was renamed Lone Star NGL LLC (“Lone Star”).

Lone Star owns and operates a natural gas liquids storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in West Texas, passes through the Barnett Shale production area in North Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana. The acquisition of Lone Star significantly expands the Partnership’s asset portfolio by adding a NGL platform with storage, transportation and fractionation capabilities. This acquisition is expected to provide us with additional consistent fee-based revenues.

ETP accounted for the LDH Acquisition using the acquisition method of accounting. Lone Star’s results of operations are consolidated into our ETP reporting segment, except for Lone Star’s 20% investment in a processing plant, while Lone Star’s results are recorded as an equity method investment in our Regency reporting segment. Regency’s equity method investment in Lone Star is reflected by ETP as noncontrolling interest attributable to Lone Star. These amounts have been eliminated in our consolidated financial statements.

The following summarizes the preliminary assets acquired and liabilities assumed recognized at the acquisition date:

 

Total current assets

   $ 118,371   

Property, plant and equipment (1)

     1,438,704   

Goodwill

     408,285   

Intangible assets

     83,000   

Other assets

     157   
  

 

 

 
     2,048,517   
  

 

 

 

Total current liabilities

     76,850   

Other long-term liabilities

     438   
  

 

 

 
     77,288   
  

 

 

 

Total consideration

     1,971,229   

Cash received

     31,231   
  

 

 

 

Total consideration, net of cash received

   $ 1,939,998   
  

 

 

 

 

  (1) 

Property, plant and equipment consists of the following:

 

Pipelines and equipment (65 years)

   $ 1,051,211   

Natural gas liquids storage (40 years)

     356,242   

Construction work-in-process

     31,251   
  

 

 

 

Property, plant and equipment

   $ 1,438,704   
  

 

 

 

 

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Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and six months ended June 30, 2011 and 2010 are presented as if the acquisitions of LDH and Regency had been completed on January 1, 2010:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  

Revenues

   $ 2,011,513       $ 1,659,528       $ 4,072,615       $ 3,932,061   

Net income

     100,768         19,233         297,298         208,823   

Net income attributable to partners

     64,881         74,673         152,804         173,799   

Basic net income per Limited Partner unit

     0.29         0.33         0.69         0.78   

Diluted net income per Limited Partner unit

     0.29         0.33         0.69         0.78   

The pro forma consolidated results of operations include adjustments to:

 

   

include the results of LDH and Regency for all periods presented;

 

   

include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;

 

   

include incremental interest expense related to financing the purchase price;

 

   

adjust for one-time expenses; and

 

   

adjust for relative changes in ownership resulting from both transactions.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

The accounting for this transaction is based on the preliminary purchase price allocation, which is pending final working capital settlements.

Pending Acquisition

On July 19, 2011, we entered into a Second Amended and Restated Plan of Merger (the “Second Amended SUG Merger Agreement”) with Sigma Acquisition Corporation, a Delaware corporation and our wholly-owned subsidiary (“Merger Sub”), and Southern Union Company (“SUG”), a Delaware corporation. The Second Amended SUG Merger Agreement modifies certain terms of the Amended and Restated Agreement and Plan of Merger entered into by us, Merger Sub and SUG on July 4, 2011. Under the terms of the Second Amended SUG Merger Agreement, Merger Sub will merge with and into SUG, with SUG continuing as the surviving entity and becoming our wholly-owned subsidiary (the “SUG Merger”) subject to certain conditions to close. Pursuant to the Second Amended SUG Merger Agreement, ETE would acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.

Consummation of the SUG Merger is subject to customary conditions, including, without limitation: (i) the adoption of the Second Amended SUG Merger Agreement by the stockholders of SUG, (ii) the expiration or early termination of the waiting period applicable to the SUG Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the “HSR Act”), as amended, and any required approvals thereunder, (iii) the receipt of required approvals from the Federal Energy Regulatory Commission (“FERC”), the Missouri Public Service Commission and, if required, the Massachusetts Department of Public Utilities, (iv) the effectiveness of a registration statement on Form S-4 relating to the ETE Common Units to be issued in the SUG Merger, and (v) the absence of any law, injunction, judgment or ruling prohibiting or restraining the SUG Merger or making the consummation of the SUG Merger illegal. On July 28, 2011, the waiting period applicable to the SUG Merger under the HSR Act expired.

Citrus Transaction

On July 19,2011, ETP entered into an Amended and Restated Agreement and Plan of Merger with us (the “Amended Citrus Merger Agreement”). The Amended Citrus Merger Agreement modifies certain terms of the Agreement and Plan of Merger entered into by ETP and us on July 4, 2011. Pursuant to the terms of the Second Amended SUG Merger Agreement, immediately prior to the effective time of the SUG Merger, we will assign and SUG will assume the benefits and obligations of us under the Amended Citrus Merger Agreement.

Under the Amended Citrus Merger Agreement, it is anticipated that SUG will cause the contribution to ETP of a 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission pipeline system and is currently jointly owned by SUG and El Paso Corporation (the “Citrus Transaction”). The Citrus Transaction will be effected through the merger of Citrus ETP Acquisition, L.L.C., a Delaware limited liability company and wholly-owned subsidiary of SUG that indirectly owns a 50% interest in Citrus Corp. (“CrossCountry”). In exchange for the interest in Citrus Corp., SUG will receive approximately $2.0 billion, consisting of $1.895 billion in cash and $105 million of ETP Common Units, with the value of the ETP Common Units based on the volume-weighted average trading price for the 10 consecutive trading days ending immediately prior to the date that is three trading days prior to the closing date of the Citrus Transaction. In order to increase the expected accretion to be derived from the Citrus Transaction, we have agreed to relinquish our rights to approximately $220 million of incentive distributions from ETP that we would otherwise be entitled to receive over 16 consecutive quarters following the closing of the transaction.

 

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The Amended Citrus Merger Agreement includes customer representations, warranties and covenants of ETP and us (including representations, warranties and covenants relating to SUG, CrossCountry and certain of CrossCountry’s affiliates). Consummation of the Citrus Transaction is subject to customary conditions, including, without limitation: (i) satisfaction or waiver of the closing conditions set forth in the Second Amended SUG Merger Agreement, (ii) the receipt by ETP of any necessary waivers or amendments to its credit agreements, (iii) the amendment of ETP’s partnership agreement to reflect the agreed upon relinquishment by us of incentive distributions from ETP discussed above, and (iv) the absence of any order, decree, injunction or law prohibiting or making the consummation of the transactions contemplated by the Amended Citrus Merger Agreement illegal. The Amended Citrus Merger Agreement contains certain termination rights for both us and ETP, including among others, the right to terminate if the Citrus Transaction is not completed by December 31, 2012 or if the Second Amended Merger SUG Agreement is terminated.

Pursuant to the Amended Citrus Merger Agreement, we have has granted ETP a right of first offer with respect to any disposition by us or SUG of Southern Union Gas Services, a subsidiary of SUG that owns and operates a natural gas gathering and processing system serving the Permian Basin in West Texas and New Mexico.

 

4. CASH AND CASH EQUIVALENTS:

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

The net change in operating assets and liabilities (net of effects of acquisitions) included in cash flows from operating activities is comprised as follows:

 

     Six Months Ended
June 30,
 
     2011     2010  

Accounts receivable

   $ 40,057      $ 98,321   

Accounts receivable from related companies

     (38,515     21,603   

Inventories

     30,181        159,540   

Exchanges receivable

     2,599        13,151   

Other current assets

     (19,484     35,792   

Intangibles and other assets

     4,241        4,201   

Accounts payable

     (31,956     (66,853

Accounts payable to related companies

     23,902        (12,096

Exchanges payable

     2,970        (7,880

Accrued and other current liabilities

     17,892        38,036   

Other non-current liabilities

     11,108        (583 )  

Price risk management assets and liabilities, net

     (21,794    
53,085
  
  

 

 

   

 

 

 

Net change in operating assets and liabilities, net of effects of acquisitions

   $ 21,201      $ 336,317   
  

 

 

   

 

 

 

 

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Non-cash investing activities are as follows:

 

     Six Months Ended
June 30,
 
     2011      2010  

Accrued capital expenditures

   $ 106,047       $ 73,432   
  

 

 

    

 

 

 

Gain from subsidiary common unit transactions

   $ 92,074       $ 280,492   
  

 

 

    

 

 

 

 

5. INVENTORIES:

Inventories consisted of the following:

 

     June 30,
2011
     December 31,
2010
 

Natural gas and NGLs, excluding propane

   $ 176,093       $ 170,179   

Propane

     59,213         76,341   

Appliances, parts and fittings and other

     112,871         119,864   
  

 

 

    

 

 

 

Total inventories

   $ 348,177       $ 366,384   
  

 

 

    

 

 

 

ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.

 

6. GOODWILL, INTANGIBLES AND OTHER ASSETS:

A net increase in goodwill of $408.3 million was recorded during the six months ended June 30, 2011 primarily due to the LDH Acquisition referenced in Note 3. This additional goodwill is expected to be deductible for tax purposes. In addition, ETP recorded customer contracts of $83.0 million with useful lives ranging from 3 to 14 years.

Components and useful lives of intangibles and other assets were as follows:

 

     June 30, 2011     December 31, 2010  
     Gross
Carrying
Amount
     Accumulated
Amortization
    Gross
Carrying
Amount
     Accumulated
Amortization
 

Amortizable intangible assets:

          

Customer relationships, contracts and agreements (3 to 46 years)

   $ 1,053,788       $ (109,657   $ 971,657       $ (88,583

Trade names (20 years)

     65,500         (2,993     65,500         (1,910

Noncompete agreements (3 to 15 years)

     20,187         (12,219     21,165         (11,888

Patents (9 years)

     750         (160     750         (118

Other (10 to 15 years)

     1,320         (544     1,320         (492
  

 

 

    

 

 

   

 

 

    

 

 

 

Total amortizable intangible assets

     1,141,545         (125,573     1,060,392         (102,991

Non-amortizable intangible assets:

          

Trademarks

     77,655                77,445           
  

 

 

    

 

 

   

 

 

    

 

 

 

Total intangible assets

     1,219,200         (125,573     1,137,837         (102,991

Other assets:

          

Financing costs (3 to 30 years)

     157,882         (47,140     137,012         (38,945

Regulatory assets

     107,258         (16,381     107,384         (14,445

Other

     31,136         (658     35,001         (426
  

 

 

    

 

 

   

 

 

    

 

 

 

Total intangibles and other assets

   $ 1,515,476       $ (189,752   $ 1,417,234       $ (156,807
  

 

 

    

 

 

   

 

 

    

 

 

 

 

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Aggregate amortization expense of intangibles and other assets was as follows:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  

Reported in depreciation and amortization

   $ 12,204       $ 7,910       $ 25,345       $ 13,056   
  

 

 

    

 

 

    

 

 

    

 

 

 

Reported in interest expense

   $ 5,005       $ 3,728       $ 9,577       $ 6,645   
  

 

 

    

 

 

    

 

 

    

 

 

 

Estimated aggregate amortization expense for the next five years is as follows:

 

Years Ending December 31:

      

2012

   $ 70,449   

2013

     65,243   

2014

     62,222   

2015

     57,776   

2016

     56,250   

 

7. FAIR VALUE MEASUREMENTS:

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.

Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2011 was $12.02 billion and $11.15 billion, respectively. As of December 31, 2010, the aggregate fair value and carrying amount of our consolidated debt obligations was $10.23 billion and $9.38 billion, respectively.

We have marketable securities, commodity derivatives, interest rate derivatives, the Preferred Units and embedded derivatives in the Preferred Units of a Subsidiary (the “Regency Preferred Units”) that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. The fair value of the Preferred Units was based predominantly on an income approach model and is also considered Level 3.

 

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2011 and December 31, 2010 based on inputs used to derive their fair values:

 

     Fair Value Measurements at
June 30, 2011 Using
 
     Fair Value
Total
    Level 1     Level 2     Level 3  

Assets:

        

Marketable securities

   $ 1,996      $ 1,996      $      $   

Interest rate derivatives

     18,854               18,854          

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

     81,744        81,744                 

Swing Swaps IFERC

     8,258        1,371        6,887          

Fixed Swaps/Futures

     19,819        18,445        1,374          

Options — Puts

     14,956               14,956          

NGLs — Forward Swaps

     67               67          

Propane — Forward Swaps

     557               557          
  

 

 

   

 

 

   

 

 

   

 

 

 

Total commodity derivatives

     125,401        101,560        23,841          
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Assets

   $ 146,251      $ 103,556      $ 42,695      $   
  

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities:

        

Interest rate derivatives

   $ (9,753   $      $ (9,753   $   

Preferred Units

     (334,170                   (334,170

Embedded derivatives in the Regency Preferred Units

     (51,498                   (51,498

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

     (79,164     (79,164              

Swing Swaps IFERC

     (11,040     (2,682     (8,358       

Fixed Swaps/Futures

     (16,760     (16,760              

Options — Puts

     (27            (27       

Options — Calls

     (704            (704       

NGLs — Forward Swaps

     (16,711            (16,711       

Propane — Forward Swaps

     (281            (281       

WTI Crude Oil

     (3,651            (3,651       
  

 

 

   

 

 

   

 

 

   

 

 

 

Total commodity derivatives

     (128,338     (98,606     (29,732       
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Liabilities

   $ (523,759   $ (98,606   $ (39,485   $ (385,668
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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Table of Contents
     Fair Value Measurements at
December 31, 2010 Using
 
     Fair Value
Total
    Level 1     Level 2     Level 3  

Assets:

        

Marketable securities

   $ 2,032      $ 2,032      $      $   

Interest rate derivatives

     20,790               20,790          

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

     15,756        15,756                 

Swing Swaps IFERC

     1,682        1,562        120          

Fixed Swaps/Futures

     44,955        42,474        2,481          

Options — Calls

     75               75          

Options — Puts

     26,241               26,241          

NGLs — Forward Swaps

     192               192          

Propane — Forward Swaps

     6,864               6,864          
  

 

 

   

 

 

   

 

 

   

 

 

 

Total commodity derivatives

     95,765        59,792        35,973          
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Assets

   $ 118,587      $ 61,824      $ 56,763      $   
  

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities:

        

Interest rate derivatives

   $ (20,922   $      $ (20,922   $   

Preferred Units

     (317,600                   (317,600

Embedded derivatives in the Regency Preferred Units

     (57,023                   (57,023

Commodity derivatives:

        

Natural Gas:

        

Basis Swaps IFERC/NYMEX

     (17,372     (17,372              

Swing Swaps IFERC

     (3,768     (3,520     (248       

Fixed Swaps/Futures

     (42,252     (41,825     (427       

Options — Calls

     (2,643            (2,643       

Options — Puts

     (7            (7       

NGLs — Forward Swaps

     (10,684            (10,684       

WTI Crude Oil

     (3,581            (3,581       
  

 

 

   

 

 

   

 

 

   

 

 

 

Total commodity derivatives

     (80,307     (62,717     (17,590       
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Liabilities

   $ (475,852   $ (62,717   $ (38,512   $ (374,623
  

 

 

   

 

 

   

 

 

   

 

 

 

The following table presents a reconciliation of the beginning and ending balances for liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the six months ended June 30, 2011. There were no transfers between the fair value hierarchy levels during the six months ended June 30, 2011.

 

Balance, December 31, 2010

   $ (374,623

Net unrealized losses included in other income (expense)

     (11,045
  

 

 

 

Balance, June 30, 2011

   $ (385,668
  

 

 

 

 

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Table of Contents
8. NET INCOME PER LIMITED PARTNER UNIT:

A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011     2010      2011     2010  

Basic Net Income per Limited Partner Unit:

         

Limited Partners’ interest in net income

   $ 66,080      $ 19,208       $ 154,446      $ 131,636   
  

 

 

   

 

 

    

 

 

   

 

 

 

Weighted average Limited Partner units

     222,972,708        222,941,172         222,963,741        222,941,140   
  

 

 

   

 

 

    

 

 

   

 

 

 

Basic net income per Limited Partner unit

   $ 0.30      $ 0.09       $ 0.69      $ 0.59   
  

 

 

   

 

 

    

 

 

   

 

 

 

Diluted Net Income per Limited Partner Unit:

         

Limited Partners’ interest in net income

   $ 66,080      $ 19,208       $ 154,446      $ 131,636   

Dilutive effect of equity-based compensation of subsidiaries

     (132             (402     (131
  

 

 

   

 

 

    

 

 

   

 

 

 

Diluted net income available to Limited Partners

   $ 65,948      $ 19,208       $ 154,044      $ 131,505   
  

 

 

   

 

 

    

 

 

   

 

 

 

Weighted average Limited Partner units

     222,972,708        222,941,172         222,963,741        222,941,140   
  

 

 

   

 

 

    

 

 

   

 

 

 

Diluted net income per Limited Partner unit

   $ 0.30      $ 0.09       $ 0.69      $ 0.59   
  

 

 

   

 

 

    

 

 

   

 

 

 

Discontinued operations per unit has been omitted as the impact rounds to $0.00 per unit for all relevant periods presented.

The calculation above for the three and six months ended June 30, 2011 for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units have a liquidation preference of $300.0 million and are subject to mandatory conversion as discussed in Note 10.

 

9. DEBT OBLIGATIONS:

Senior Notes

ETP Senior Notes

In May 2011, ETP completed a public offering of $800 million aggregate principal amount of 4.65% Senior Notes due June 1, 2021 and $700 million aggregate principal amount of 6.05% Senior Notes due June 1, 2041. ETP used the proceeds, net of commissions, of $1.48 billion to repay all of the borrowings outstanding under its revolving credit facility (the “ETP Credit Facility”), to fund capital expenditures related to pipeline construction projects and for general partnership purposes. ETP may redeem some or all of the notes at any time and from time to time pursuant to the terms of the indenture subject to the payment of a “make-whole” premium. Interest will be paid semi-annually.

Regency Senior Notes

In May 2011, Regency issued $500.0 million aggregate principal amount of 6.5% Senior Notes due July 15, 2021 (the “Regency 2021 Notes”). Regency used the proceeds, net of commissions, of approximately $491.3 million to repay borrowings outstanding under its revolving credit facility (the “Regency Credit Facility”). Regency capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the Regency 2021 Notes. Interest will be paid semi-annually.

At any time prior to July 15, 2016, Regency may redeem some or all of the Regency 2021 Notes at a redemption price equal to 100% of the principal amount plus a “make-whole” premium, plus accrued and unpaid interest to the redemption date. At any time before July 15, 2014, Regency may redeem up to 35% of the aggregate principal amount of the Regency 2021 Notes then outstanding

 

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at a redemption price equal to 106.5% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to the redemption date.

Upon the occurrence of a change of control event, as defined in the indenture, followed by a rating decline within 90 days, each holder of the Regency 2021 Notes will be entitled to require Regency to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. Regency’s ability to purchase the notes upon a change of control will be limited by the terms of its debt agreements, including Regency’s revolving credit facility.

The Regency 2021 Notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries to:

 

   

incur additional indebtedness;

 

   

pay distributions on, or repurchase or redeem equity interests;

 

   

make certain investments;

 

   

incur liens;

 

   

enter into certain types of transactions with affiliates; and

 

   

sell assets, consolidate or merge with or into other companies.

Revolving Credit Facilities

Parent Company Credit Agreement

The Parent Company has a $200 million senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. The Parent Company Credit Agreement is secured by all tangible or intangible assets of ETE and certain of its subsidiaries. As of June 30, 2011, there were no outstanding borrowings under the Parent Company Credit Agreement.

ETP Credit Facility

The ETP Credit Facility provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity). The ETP Credit Facility matures on July 20, 2012, unless ETP elects the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). As of June 30, 2011, ETP had a balance of $144.0 million outstanding under the ETP Credit Facility, and the amount available for future borrowings was $1.81 billion taking into account letters of credit of $42.9 million. The weighted average interest rate on the total amount outstanding as of June 30, 2011 was 0.76%.

Regency Credit Facility

The Regency Credit Facility has aggregate revolving commitments of $900 million that matures June 15, 2014. As of June 30, 2011, there was a balance outstanding under the Regency Credit Facility of $330.0 million in revolving credit loans and approximately $11.0 million in letters of credit. The total amount available under the Regency Credit Facility, as of June 30, 2011, which is reduced by any letters of credit, was approximately $559.0 million. The weighted average interest rate on the total amount outstanding as of June 30, 2011 was 3.25%.

 

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Covenants Related to Our Credit Agreements

We, ETP and Regency are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of June 30, 2011.

 

10. REDEEMABLE PREFERRED UNITS:

ETE Preferred Units

In connection with the Regency Transactions completed in May 2010, ETE issued 3,000,000 Series A Convertible Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of $300.0 million and were reflected as a non-current liability in our consolidated balance sheets as of June 30, 2011 and December 31, 2010. The Series A Convertible Preferred Units are measured at fair value on a recurring basis. Changes in the estimated fair value of the ETE Preferred Units are recorded in other income (expense) on the consolidated statements of operations.

Regency Preferred Units

Regency has 4,371,586 Regency Preferred Units outstanding at June 30, 2011, which were convertible into 4,620,152 Regency Common Units. If outstanding on September 2, 2029, the Regency Preferred Units are mandatorily redeemable for $80.0 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed quarterly cash distributions of $0.445 per unit from Regency. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s Partnership Agreement.

The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:

 

     Regency
Preferred Units
     Amount  

Balance as of December 31, 2010

     4,371,586       $ 70,943   

Accretion to redemption value

             97   
  

 

 

    

 

 

 

Ending balance as of June 30, 2011

     4,371,586       $ 71,040   
  

 

 

    

 

 

 

 

11. EQUITY:

Common Units Issued

The change in ETE Common Units during the six months ended June 30, 2011 was as follows:

 

     Number of
Units
 

Balance, December 31, 2010

     222,941,172   

Issuance of restricted common units under equity incentive plans

     31,536   
  

 

 

 

Balance, June 30, 2011

     222,972,708   
  

 

 

 

Sales of Common Units by Subsidiaries

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Regency and the underlying book value arising from the issuance or redemption of units by ETP or Regency (excluding transactions with the Parent Company) as capital transactions.

As a result of ETP’s and Regency’s issuances of Common Units during the six months ended June 30, 2011, we recognized increases in partners’ capital of $92.1 million.

 

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Sale of Common Units by ETP

On April 1, 2011, ETP issued 14,202,500 Common Units through a public offering. The proceeds, net of commissions, of approximately $695.5 million were used to repay amounts outstanding under the ETP Credit Facility, to fund capital expenditures related to pipeline construction projects and for general partnership purposes.

ETP has an Equity Distribution Agreement with Credit Suisse Securities (USA) LLC (“Credit Suisse”) under which ETP may offer and sell from time to time through Credit Suisse, as its sales agent, ETP Common Units having an aggregate offering price of up to $200.0 million. During the six months ended June 30, 2011, ETP received proceeds from units issued pursuant to this agreement of approximately $72.9 million, net of commissions, which were used for general partnership purposes. Approximately $101.2 million of ETP Common Units remain available to be issued under the Equity Distribution Agreement based on trades initiated through June 30, 2011.

In April 2011, ETP filed a registration statement with the SEC covering ETP’s Distribution Reinvestment Plan (the “DRIP”). The DRIP provides Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units. Currently, the registration statement covers the issuance of up to 5,750,000 ETP Common Units under the DRIP.

In May 2011, in conjunction with the payment of ETP’s distribution for the quarter ended March 31, 2011, distributions of approximately $1.9 million were reinvested under the DRIP resulting in the issuance of 41,139 ETP Common Units.

Sale of Common Units by Regency

In May 2011, Regency issued 8,500,001 Regency Common Units in a private placement. The net proceeds of $203.9 million from the from the private placement were used to fund a portion of Regency’s 30% ownership interest in Lone Star, as discussed in Note 3.

Parent Company Quarterly Distributions of Available Cash

The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Regency related to limited and general partnership interests, including IDRs. We currently have no independent operations outside of our interests in ETP and Regency.

Following are distributions declared and/or paid by us subsequent to December 31, 2010:

 

Quarter Ended

 

Record Date

 

Payment Date

 

Rate

December 31, 2010

  February 7, 2011   February 18, 2011   $0.540

March 31, 2011

  May 6, 2011   May 19, 2011   0.560

June 30, 2011

  August 5, 2011   August 19, 2011
  0.625

The distribution for the quarter ended June 30, 2011 was announced on June 30, 2011 and was reflected as an accrued distribution to ETE partners on our consolidated balance sheet as of June 30, 2011.

ETP’s Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2010:

 

Quarter Ended

 

Record Date

 

Payment Date

 

Rate

December 31, 2010

  February 7, 2011   February 14, 2011   $0.89375

March 31, 2011

  May 6, 2011   May 16, 2011   0.89375

June 30, 2011

  August 5, 2011   August 15, 2011   0.89375

 

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Regency’s Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2010:

 

Quarter Ended

 

Record Date

 

Payment Date

 

Rate

December 31, 2010

  February 7, 2011   February 14, 2011   $0.445

March 31, 2011

  May 6, 2011   May 13, 2011   0.445

June 30, 2011

  August 5, 2011   August 12, 2011   0.450

Accumulated Other Comprehensive Income (Loss)

The following table presents the components of accumulated other comprehensive (loss) income (“AOCI”), net of tax:

 

     June 30,
2011
    December 31,
2010
 

Net gains on commodity related hedges

   $ (6,279   $ 14,146   

Unrealized gains on available-for-sale securities

     883        918   
  

 

 

   

 

 

 

Subtotal

     (5,396     15,064   

Amounts attributable to noncontrolling interest

     5,040        (10,266
  

 

 

   

 

 

 

Total AOCI included in partners’ capital, net of tax

   $ (356   $ 4,798   
  

 

 

   

 

 

 

 

12. UNIT-BASED COMPENSATION PLANS:

We, ETP, and Regency have equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards.

ETE Long-Term Incentive Plan

During the six months ended June 30, 2011, ETE employees were granted a total of 30,000 unvested awards with five-year service vesting requirements. The weighted average grant-date fair value of these awards was $39.82 per unit. As of June 30, 2011 a total of 105,713 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $1.7 million in compensation expense over a weighted average period of 2.1 years related to unvested awards.

ETP Unit-Based Compensation Plans

During the six months ended June 30, 2011, ETP employees were granted a total of 518,700 unvested awards with five-year service vesting requirements, and directors were granted a total of 2,580 unvested awards with three-year service vesting requirements. The weighted average grant-date fair value of these awards was $53.60 per unit. As of June 30, 2011 a total of 2,450,698 unit awards remain unvested, including the new awards granted during the period. We expect to recognize a total of $69.2 million in compensation expense over a weighted average period of 1.7 years related to unvested awards.

Regency Unit-Based Compensation Plans

Common Unit Options

During the six months ended June 30, 2011, no Regency Common Unit options were granted. As of June 30, 2011, a total of 166,050 Regency Common Unit options remain vested and exercisable, with a weighted average exercise price of $22.13 per Regency Common Unit option.

Phantom Units

During the six months ended June 30, 2011, Regency employees and directors were granted 68,745 Regency phantom units with three-year service vesting requirements. As of June 30, 2011, a total of 718,172 Regency Phantom Units remain unvested, with a weighted average grant date fair value of $24.77. We expect to recognize a total of $13.0 million in compensation expense over a weighted average period of 4.2 years related to Regency’s unvested phantom units.

 

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13. INCOME TAXES:

The components of the federal and state income tax expense of our taxable subsidiaries are summarized as follows:

 

     Three Months
Ended June 30,
    Six Months Ended
June 30,
 
     2011     2010     2011     2010  

Current expense:

        

Federal

   $ 561      $ 1,739      $ 5,663      $ 3,057   

State

     5,439        4,344        9,435        7,502   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total current expense

     6,000        6,083        15,098        10,559   
  

 

 

   

 

 

   

 

 

   

 

 

 

Deferred expense (benefit):

        

Federal

     (747     (1,723     (559     (1,029

State

     (29     (307     588        (266
  

 

 

   

 

 

   

 

 

   

 

 

 

Total deferred expense (benefit)

     (776     (2,030     29        (1,295
  

 

 

   

 

 

   

 

 

   

 

 

 

Total income tax expense

   $ 5,224      $ 4,053      $ 15,127      $ 9,264   
  

 

 

   

 

 

   

 

 

   

 

 

 

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level.

 

14. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Guarantee — Fayetteville Express Pipeline LLC

Fayetteville Express Pipeline LLC (“FEP”), a joint venture entity in which ETP owns a 50% interest, had a credit agreement that provided for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP guaranteed 50% of the obligations of FEP under the FEP Facility, with the remainder of FEP Facility obligations guaranteed by Kinder Morgan Energy Partners, L.P. (“KMP”). Amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate.

As of June 30, 2011, FEP had $968.5 million of outstanding borrowings issued under the FEP Facility and ETP’s contingent obligation with respect to its guaranteed portion of FEP’s outstanding borrowings was $484.3 million, which was not reflected in our consolidated balance sheet. The weighted average interest rate on the total amount outstanding as of June 30, 2011 was 3.09%.

In July 2011, the FEP Facility was repaid with capital contributions from ETP and KMP totaling $390 million along with proceeds from a $600 million term loan credit facility maturing in July 2012 (which can be extended for one year at the option of FEP). Upon closing and funding of the term loan facility, the FEP Facility was terminated. FEP also entered into a $50 million revolving credit facility maturing in July 2015. ETP does not guarantee FEP’s indebtedness under its term loan or new credit facility.

NGL Pipeline Regulation

ETP and Regency have interests in NGL pipelines located in Texas. ETP and Regency believe that these pipelines do not provide interstate service and that they are thus not subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of ETP’s and Regency’s NGL facilities will remain unchanged; however, should they be found jurisdictional, the FERC’s rate-making methodologies may limit ETP’s and Regency’s ability to set rates based on their actual costs, may delay the use of rates that reflect increased costs and may subject ETP and Regency to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.

Commitments

In the normal course of our business, ETP and Regency purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP has also entered into several propane purchase and supply commitments, which are typically one year agreements with varying terms as to quantities, prices and expiration dates. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately $7.8 million and $5.8 million for the three months ended June 30, 2011 and 2010. For the six months ended June 30, 2011 and 2010, rental expense for operating leases totaled approximately $13.2 million and $11.7 million, respectively.

 

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ETP’s propane operations have an agreement with Enterprise Products Partners L.P. (together with its subsidiaries “Enterprise”) (see Note 16) to supply a portion of its propane requirements. The agreement will continue until March 2015 and includes an option to extend the agreement for an additional year.

In connection with the sale of ETP’s investment in M-P Energy in October 2007, ETP executed a propane purchase agreement for approximately 90.0 million gallons per year through 2015 at market prices plus a nominal fee.

ETP’s and Regency’s joint venture agreements require that ETP and Regency fund their proportionate shares of capital contributions to their unconsolidated affiliates. ETP and Regency expect that such capital contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and propane are flammable, combustible gases. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of June 30, 2011 and December 31, 2010, accruals of approximately $10.7 million and $10.2 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty, and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Further, we may revise accrual amounts prior to the resolution of a particular contingency based on changes in facts and circumstances or in the expected outcome.

No amounts have been recorded in our June 30, 2011 or December 31, 2010 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that can require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Moreover, there can be no assurance that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, will not result in substantial costs and liabilities.

 

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We are unable to estimate any losses or range of losses that could result from such developments. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

Our operations are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the U.S. Department of Transportation (“DOT”). We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

ETP Environmental Matters

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of ETP’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, ETP believes that such costs will not have a material adverse effect on its financial position.

As of June 30, 2011 and December 31, 2010, accruals related to ETP on an undiscounted basis of $12.8 million and $13.8 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities related to environmental matters.

Based on information available at this time and reviews undertaken to identify potential exposure, ETP believes the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”). The costs of this work are not eligible for recovery in rates. ETP’s total accrued future estimated cost of remediation activities expected to continue through 2025 is $8.1 million, which is included in the aggregate environmental accruals discussed above. Transwestern received approval from the FERC for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.

Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

The U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of ETP’s facilities. ETP is currently reviewing the impact to its operations and expects to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but ETP believes such costs will not have a material adverse effect on its financial position, results of operations or cash flows.

 

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Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. ETP has not been named as a potentially responsible party at any of these sites, nor has its operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our June 30, 2011 consolidated balance sheets or our December 31, 2010 consolidated balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require ETP to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. On October 19, 2010, industry groups submitted a legal challenge to the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to EPA for some monitoring aspects of the rule. The legal challenge has been held in abeyance since December 3, 2010, pending EPA’s consideration of the Petition for Administrative Reconsideration. On January 5, 2011, the EPA approved the request for reconsideration of the monitoring issues and on March 9, 2011, EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If significant adverse comments are filed on the direct final rule, EPA would address public comments in a subsequent final rule. At this point, we cannot predict how the direct final rule might be modified as a result of the comments received or a future court ruling and as a result we cannot currently accurately predict the cost to comply with the rule’s requirements. Compliance with the final rule is required by October 2013.

On June 29, 2011, the EPA finalized a rule under the CAA that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule will become effective on August 29, 2011. The rule modifications may require ETP to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if it replaces equipment or expands existing facilities in the future. At this point, ETP is not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes ETP might make in the future.

ETP’s pipeline operations are subject to regulation by the DOT under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. For the three months ended June 30, 2011 and 2010, $3.9 million and $3.6 million, respectively, of capital costs and $3.9 million and $4.4 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. For the six months ended June 30, 2011 and 2010, $5.6 million and $5.0 million, respectively, of capital costs and $6.0 million and $6.3 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

 

15. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To manage the impact of volatility from these prices, our subsidiaries utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by segment as well as tables detailing the outstanding commodity-related derivatives as of June 30, 2011 and December 31, 2010 by segment.

 

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Investment in ETP

ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price. ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities.). At the inception of the hedge, ETP will lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP will value the hedged natural gas inventory at current spot market prices along with the financial derivative it uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of its derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that it recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdrawal of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in its intrastate transportation and storage operations and operational gas sales in its interstate transportation operations. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statements of operations.

Derivatives are utilized in ETP’s midstream operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. ETP attempts to maintain balanced positions in its marketing activities to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by its long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance ETP’s positions. To the extent open commodity positions exist, fluctuating commodity prices can impact its financial position and results of operations, either favorably or unfavorably.

ETP’s propane operations permit customers to guarantee the propane delivery price for the next heating season. As ETP executes fixed sales price contracts with its customers, it may enter into propane futures contracts to fix the purchase price related to these sales contracts, thereby locking in a gross profit margin. Additionally, ETP may use propane futures contracts to secure the purchase price of its propane inventory for a percentage of its anticipated propane sales.

 

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The following table details ETP’s outstanding commodity-related derivatives:

 

     June 30, 2011    December 31, 2010
     Notional
Volume
    Maturity    Notional
Volume
    Maturity

Mark-to-Market Derivatives

         

Natural Gas:

         

Basis Swaps IFERC/NYMEX (MMBtu)

     (26,145,000   2011-2013      (38,897,500   2011

Swing Swaps IFERC (MMBtu)

     (144,420,000   2011-2012      (19,720,000   2011

Fixed Swaps/Futures (MMBtu)

     6,695,000      2011-2012      (2,570,000   2011

Options — Calls (MMBtu)

               (3,000,000   2011

Propane:

         

Forwards/Swaps (Gallons)

               1,974,000      2011

Fair Value Hedging Derivatives

         

Natural Gas:

         

Basis Swaps IFERC/NYMEX (MMBtu)

     (26,040,000   2011-2012      (28,050,000   2011

Fixed Swaps/Futures (MMBtu)

     (38,285,000   2011-2012      (39,105,000   2011

Hedged Item — Inventory (MMBtu)

     38,285,000      2011      39,105,000      2011

Cash Flow Hedging Derivatives

         

Natural Gas:

         

Fixed Swaps/Futures (MMBtu)

     920,000      2011      (210,000   2011

Options — Puts (MMBtu)

     15,180,000      2011-2012      26,760,000      2011-2012

Options — Calls (MMBtu)

     (15,180,000   2011-2012      (26,760,000   2011-2012

Propane:

         

Forwards/Swaps (Gallons)

     14,700,000      2011-2012      32,466,000      2011

We expect gains of $10.4 million related to ETP’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Investment in Regency

Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand, as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.

Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency’s General Partner have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency’s General Partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of Regency’s General Partner is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency’s Risk Management Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.

Regency’s Preferred Units (see Note 10) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to affect its cash flows.

 

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The following table details Regency’s outstanding commodity-related derivatives:

 

     June 30, 2011    December 31, 2010
     Notional
Volume
     Maturity    Notional
Volume
     Maturity

Cash Flow Hedging Derivatives

           

Natural Gas:

           

Fixed Swaps/Futures (MMBtu)

     3,670,000       2011-2012      3,830,000       2011

Propane:

           

Forwards/Swaps (Gallons)

     18,564,000       2011-2013      18,648,000       2011-2012

Natural Gas Liquids:

           

Forwards/Swaps (Barrels)

     1,006,000       2011-2013      1,212,110       2011-2012

WTI Crude Oil:

           

Forwards/Swaps (Barrels)

     483,000       2011-2014      373,655       2011-2012

We expect gains of $16.4 million related to Regency’s commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage our current interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances. The following is a summary of interest rate swaps outstanding as of June 30, 2011 and December 31, 2010, none of which were designated as hedges for accounting purposes:

 

              Notional Amount
Outstanding
 

Entity

   Term  

Type (1)

   June 30,
2011
     December 31,
2010
 

ETP

   August 2012 (2)   Forward starting to pay a fixed rate of 3.64% and receive a floating rate    $ 400,000       $ 400,000   

ETP

   July 2013 (3)   Forward starting to pay a fixed rate of 4.13% and receive a floating rate      200,000           

ETP

   July 2018   Pay a floating rate plus a spread and receive a fixed rate of 6.70%      500,000         500,000   

Regency

   April 2012   Pay a fixed rate of 1.325% and receive a floating rate      250,000         250,000   

 

  (1) 

Floating rates are based on LIBOR.

  (2) 

These forward starting swaps have an effective date of August 2012 and a term of 10 years; however, the swaps have a mandatory termination provision and will be settled in August 2012.

  (3) 

These forward starting swaps have an effective date of July 2013 and a term of 10 years; however, the swaps have a mandatory termination provision and will be settled in July 2013.

Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposures associated with a single counterparty.

Our counterparties consist primarily of petrochemical companies, other industrial, mid-size to major oil and gas companies and power companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty performance.

 

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ETP utilizes master-netting agreements and has maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives. ETP exchanges margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in our consolidated balance sheets. ETP had net deposits with counterparties of $60.9 million and $52.2 million as of June 30, 2011 and December 31, 2010, respectively.

Regency is exposed to credit risk from its derivative counterparties. Although Regency does not require collateral from these counterparties, Regency deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary

The following table provides a balance sheet overview of consolidated derivative assets and liabilities as of June 30, 2011 and December 31, 2010:

 

     Fair Value of Derivative Instruments  
     Asset Derivatives      Liability Derivatives  
     June 30,
2011
     December 31,
2010
     June 30,
2011
    December 31,
2010
 

Derivatives designated as hedging instruments:

          

Commodity derivatives (margin deposits)

   $ 23,729       $ 35,031       $ (2,136   $ (6,631

Commodity derivatives

     2,001         9,263         (20,696     (14,692
                                  
     25,730         44,294         (22,832     (21,323
                                  

Derivatives not designated as hedging instruments:

          

Commodity derivatives (margin deposits)

   $ 111,866       $ 64,940       $ (117,701   $ (72,729

Commodity derivatives

             275                  

Interest rate derivatives

     18,854         20,790         (9,753     (20,922

Embedded derivatives in Regency Preferred Units

                     (51,498     (57,023
                                  
     130,720         86,005         (178,952     (150,674
                                  

Total derivatives

   $ 156,450       $ 130,299       $ (201,784   $ (171,997
                                  

The commodity derivatives (margin deposits) are recorded in “Other current assets” on our consolidated balance sheets. The remainder of the derivatives are recorded in “Price risk management assets/liabilities.”

We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

 

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The following tables summarize the amounts recognized with respect to consolidated derivative financial instruments for the periods presented:

 

     Change in Value Recognized in OCI on Derivatives
(Effective Portion)
 
     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2011      2010     2011     2010  

Derivatives in cash flow hedging relationships:

         

Commodity derivatives

   $ 3,769       $ (9,150   $ (7,123   $ 24,957   

Interest rate derivatives

             (9,955            (20,155
  

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ 3,769       $ (19,105   $ (7,123   $ 4,802   
  

 

 

    

 

 

   

 

 

   

 

 

 

 

     Location of Gain/(Loss)
Reclassified from
AOCI into Income
(Effective Portion)
   Amount of Gain/(Loss)
Reclassified from AOCI into Income
(Effective Portion)
 
          Three Months Ended
June  30,
    Six Months Ended
June 30,
 
          2011     2010     2011      2010  

Derivatives in cash flow hedging relationships:

            

Commodity derivatives

   Cost of products sold    $ (2,148   $ 7,058      $ 12,954       $ 12,373   

Interest rate derivatives

   Interest expense             (8,619             (15,885
     

 

 

   

 

 

   

 

 

    

 

 

 

Total

      $ (2,148   $ (1,561   $ 12,954       $ (3,512
     

 

 

   

 

 

   

 

 

    

 

 

 
     Location of Gain/(Loss)
Reclassified from
AOCI into Income
(Ineffective Portion)
   Amount of Gain/(Loss) Recognized in
Income on Ineffective Portion
 
          Three Months Ended
June 30,
    Six Months Ended
June 30,
 
          2011     2010     2011      2010  

Derivatives in cash flow hedging relationships:

            

Commodity derivatives

   Cost of products sold    $ 96      $ (1,016   $ 189       $ 105   
     

 

 

   

 

 

   

 

 

    

 

 

 

Total

      $ 96      $ (1,016   $ 189       $ 105   
     

 

 

   

 

 

   

 

 

    

 

 

 
     Location of Gain/(Loss)
Recognized in Income
on Derivatives
   Amount of Gain/
(Loss) Recognized in Income
Representing Hedge  Ineffectiveness and Amount
Excluded from the Assessment of Effectiveness
 
          Three Months Ended
June  30,
    Six Months Ended
June  30,
 
          2011     2010     2011      2010  

Derivatives in fair value hedging relationships (including hedged item):

            

Commodity derivatives

   Cost of products sold    $ 15,874      $ 6,417      $ 22,291       $ (967
     

 

 

   

 

 

   

 

 

    

 

 

 

Total

      $ 15,874      $ 6,417      $ 22,291       $ (967
     

 

 

   

 

 

   

 

 

    

 

 

 

 

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Location of Gain/(Loss)
Recognized in Income
on Derivatives

   Amount of Gain/(Loss)
Recognized in Income
on Derivatives
 
          Three Months Ended
June  30,
    Six Months Ended
June 30,
 
          2011     2010     2011     2010  

Derivatives not designated as hedging instruments:

           

Commodity derivatives

   Cost of products sold    $ (11,427   $ (22,119   $ (4,989   $ (152

Interest rate derivatives

  

Gains (losses) on non-hedged interest rate derivatives

     1,883        (22,468     3,403        (36,892

Embedded Derivatives

   Other income (expenses)      2,950        (3,606     5,525        (3,606
     

 

 

   

 

 

   

 

 

   

 

 

 

Total

      $ (6,594   $ (48,193   $ 3,939      $ (40,650
     

 

 

   

 

 

   

 

 

   

 

 

 

We recognized $15.7 million and $38.8 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the three months ended June 30, 2011 and 2010, respectively. We recognized $2.1 million and $47.5 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the six months ended June 30, 2011 and 2010, respectively. In addition, for the three months ended June 30, 2011 and 2010, we recognized unrealized gains of $16.7 million and unrealized losses of $8.2 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges. For the six months ended June 30, 2011 and 2010, we recognized unrealized gains of $7.8 million and $25.0 million, respectively, on commodity derivatives and related hedged inventory accounted for as fair value hedges.

 

16. RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. For the three and six months ended June 30, 2011, the Parent Company received $4.2 million and $8.1 million in management fees from Regency related to these services. For the three and six months ended June 30, 2011, the Parent Company paid $3.4 million and $8.4 million in management fees, respectively, to ETP related to these services. For the three and six months ended June 30, 2010, the Parent Company paid $0.1 million and $0.3 million in management fees, respectively, to ETP related to these services. The management fees received from Regency for the three and six months ended June 30, 2011 reflect the reimbursement of various general and administrative services of $0.8 million and $3.1 million, respectively, for expenses incurred by ETP on behalf of Regency.

Enterprise and its subsidiaries currently hold a portion of our limited partner interest. As a result, Enterprise and its affiliates are considered related parties for financial reporting purposes.

 

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ETP and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines and ETP sells natural gas to Enterprise. ETP’s propane operations purchase a portion of its propane requirements from Enterprise pursuant to an agreement that expires in March 2015 and includes an option to extend the agreement for an additional year. Regency sells natural gas and NGLs to, and incurs NGL processing fees with Enterprise. The following table presents sales to and purchases from Enterprise:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  

ETP’s Natural Gas Operations:

           

Sales

   $ 162,107       $ 130,526       $ 298,020       $ 275,246   

Purchases

     9,736         6,936         17,960         13,533   

Regency’s Natural Gas Operations:

           

Sales

     81,055         18,501         155,969         18,501   

Purchases

     3,319         422         2,998         422   

ETP’s Propane Operations:

           

Sales

     1,441         481         10,218         10,966   

Purchases

     72,191         52,415         242,157         218,179   

As of December 31, 2010, a subsidiary of ETP, had forward mark-to-market derivatives with Enterprise for approximately 1.7 million gallons of propane for a fair value asset of $0.2 million. These forward contracts were settled as of June 30, 2011. In addition, as of June 30, 2011 and December 31, 2010, a subsidiary of ETP had forward derivatives accounted for as cash flow hedges of 14.7 million and 32.5 million gallons of propane at fair value assets of $0.3 million and $6.6 million, respectively, with Enterprise.

Under a master services agreement with RIGS Haynesville Partnership Co. (“HPC”), Regency operates and provides all employees and services for the operation and management of HPC. The related party general administrative expenses reimbursed to Regency were $4.2 million and $8.4 million for the three and six months ended June 30, 2011. For the period from May 26, 2010 to June 30, 2010, the related party general administrative expenses reimbursed to Regency were $1.4 million.

Regency’s contract compression operations provide contract compression services to HPC. HPC also provides transportation service to Regency. For the three and six months ended June 30, 2011, Regency had revenue of $6.5 million and $13.0 million, respectively, and cost of sales of $4.0 million and $8.1 million, respectively, with HPC.

 

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The following table summarizes the related party balances on our consolidated balance sheets:

 

     June 30,
2011
    December 31,
2010
 

Accounts receivable from related parties:

    

Enterprise:

    

ETP’s Natural Gas Operations

   $ 50,180      $ 36,736   

Regency’s Natural Gas Operations

     18,649        25,539   

ETP’s Propane Operations

     226        2,327   

Other

     13,455        11,729   
  

 

 

   

 

 

 

Total accounts receivable from related parties:

   $ 82,510      $ 76,331   
  

 

 

   

 

 

 

Accounts payable to related parties:

    

Enterprise:

    

ETP’s Natural Gas Operations

   $ 1,749      $ 2,687   

Regency’s Natural Gas Operations

     754        1,323   

ETP’s Propane Operations

     10,830        22,985   

Other

     1,552        356   
  

 

 

   

 

 

 

Total accounts payable to related parties:

   $ 14,885      $ 27,351   
  

 

 

   

 

 

 

ETP’s net imbalance receivable from Enterprise

   $ 592      $ 1,360   
  

 

 

   

 

 

 

Regency’s net imbalance (payable to) receivable from Enterprise

   $ (774   $ 753   
  

 

 

   

 

 

 

 

17. OTHER INFORMATION:

The tables below present additional detail for certain balance sheet captions.

Other Current Assets

Other current assets consisted of the following:

 

     June 30,
2011
     December 31,
2010
 

Deposits paid to vendors

   $ 60,861       $ 52,192   

Prepaid expenses and other

     81,473         57,167   
  

 

 

    

 

 

 

Total other current assets

   $ 142,334       $ 109,359   
  

 

 

    

 

 

 

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

     June 30,
2011
     December 31,
2010
 

Interest payable

   $ 191,206       $ 191,466   

Customer advances and deposits

     63,111         111,448   

Accrued capital expenditures

     97,702         87,260   

Accrued wages and benefits

     59,812         76,592   

Taxes payable other than income taxes

     78,271         36,204   

Income taxes payable

     2,421         8,344   

Other

     97,239         56,374   
  

 

 

    

 

 

 

Total accrued and other current liabilities

   $ 589,762       $ 567,688   
  

 

 

    

 

 

 

 

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18. REPORTABLE SEGMENTS:

Our reportable segments reflect two reportable segments, both of which conduct their business exclusively in the United States of America, as follows:

 

   

Investment in ETP — Reflects the consolidated operations of ETP.

 

   

Investment in Regency — Reflects the consolidated operations of Regency.

Each of the respective general partners of ETP and Regency has separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners. See further discussion of ETP and Regency’s operations in Note 1.

We evaluate the performance of our operating segments based on net income. The following tables present financial information by segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Related party transactions between ETP and Regency are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

The following tables present the financial information by segment for the following periods:

 

     Investment
in ETP
     Investment
in Regency
    Corporate
and Other
    Adjustments
and
Eliminations
    Total  

Three months ended June 30, 2011:

           

Revenues from external customers

   $ 1,616,748       $ 354,816      $      $ 3,342      $ 1,974,906   

Intersegment revenues

     11,347         1,682               (13,029       

Income tax expense (benefit)

     5,783         102        (661            5,224   

Net income (loss)

     156,616         14,837        (56,413     (8,388     106,652   

Three months ended June 30, 2010:

           

Revenues from external customers

   $ 1,267,706       $ 96,082      $      $ (1,260   $ 1,362,528   

Intersegment revenues

             898               (898       

Income tax expense (benefit)

     4,569         245        (761            4,053   

Net income (loss)

     42,843         (4,895     (58,427            (20,479

Six months ended June 30, 2011:

           

Revenues from external customers

   $ 3,292,795       $ 670,375      $      $ 856      $ 3,964,026   

Intersegment revenues

     22,877         3,375               (26,252       

Income tax expense (benefit)

     16,380         70        (1,323            15,127   

Net income (loss)

     403,818         29,142        (118,828     (8,388     305,744   

Six months ended June 30, 2010:

           

Revenues from external customers

   $ 3,139,687       $ 96,082      $      $ (1,260   $ 3,234,509   

Intersegment revenues

             898               (898       

Income tax expense (benefit)

     10,493         245        (1,474            9,264   

Net income (loss)

     282,954         (4,895     (94,456            183,603   

 

     As of
June 30,
2011
    As of
December 31,
2010
 

Total assets:

    

Investment in ETP

   $ 14,641,403      $ 12,149,992   

Investment in Regency

     5,428,129        4,770,204   

Corporate and Other

     450,222        469,221   

Adjustments and Eliminations

     (653,596     (10,687
  

 

 

   

 

 

 

Total

   $ 19,866,158      $ 17,378,730   
  

 

 

   

 

 

 

 

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Table of Contents

The following tables provide revenues, grouped by similar products and services, for both ETP and Regency. These amounts include transactions between ETP and Regency.

Investment in ETP

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  

Intrastate Transportation and Storage

   $ 643,653       $ 530,174       $ 1,232,331       $ 1,132,530   

Interstate Transportation

     104,850         70,079         209,951         138,348   

Midstream

     516,499         407,123         929,694         1,025,830   

NGL Transportation and Services

     90,771                 90,771           

Retail Propane and Other Retail Propane Related

     243,973         220,126         801,188         781,281   

All Other

     28,349         40,204         51,737         61,698   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total revenues

   $ 1,628,095       $ 1,267,706       $ 3,315,672       $ 3,139,687   
  

 

 

    

 

 

    

 

 

    

 

 

 

Investment in Regency

 

     Three Months Ended
June  30,
     Six Months Ended
June 30,
 
     2011      2010      2011      2010  

Gathering and Processing

   $ 303,203       $ 83,778       $ 569,175       $ 83,778   

Joint Ventures

                               

Contract Compression

     38,072         12,054         76,508         12,054   

Contract Treating

     10,842                 19,275           

Corporate and Others

     4,381         1,148         8,792         1,148   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total revenues

   $ 356,498       $ 96,980       $ 673,750       $ 96,980   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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19. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS

(unaudited)

 

     June 30,
         2011        
    December 31,
        2010         
 
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 14,383      $ 27,247   

Accounts receivable from related companies

     447        171   

Other current assets

     1,894        864   
  

 

 

   

 

 

 

Total current assets

     16,724        28,282   

ADVANCES TO AND INVESTMENTS IN AFFILIATES

     2,258,150        2,231,722   

INTANGIBLES AND OTHER ASSETS, net

     27,838        29,118   
  

 

 

   

 

 

 

Total assets

   $ 2,302,712      $ 2,289,122   
  

 

 

   

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL     

CURRENT LIABILITIES:

    

Accounts payable

   $ 304      $   

Accounts payable to related companies

     9,414        6,654   

Accrued distributions to ETE partners

     139,790          

Accrued and other current liabilities

     42,575        44,200   
  

 

 

   

 

 

 

Total current liabilities

     192,083        50,854   

LONG-TERM DEBT, less current maturities

     1,800,000        1,800,000   

SERIES A CONVERTIBLE PREFERRED UNITS

     334,170        317,600   

COMMITMENTS AND CONTINGENCIES

    

EQUITY:

    

General Partner

     88        520   

Limited Partners

     (23,273     115,350   

Accumulated other comprehensive income (loss)

     (356     4,798   
  

 

 

   

 

 

 

Total partners’ capital (deficit)

     (23,541     120,668   
  

 

 

   

 

 

 

Total liabilities and partners’ equity

   $ 2,302,712      $ 2,289,122   
  

 

 

   

 

 

 

 

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Table of Contents

STATEMENTS OF OPERATIONS

(unaudited)

 

     Three Months
Ended June 30,
    Six Months Ended
June 30,
 
     2011     2010     2011     2010  

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES

   $ (12,037   $ (15,079   $ (13,879   $ (17,415

OTHER INCOME (EXPENSE):

        

Interest expense

     (40,587     (20,210     (81,526     (36,916

Equity in earnings of affiliates

     120,626        75,362        267,268        221,740   

Losses on non-hedged interest rate derivatives

            (20,753            (35,177

Other, net

     (1,653     (88     (16,812     (212
  

 

 

   

 

 

   

 

 

   

 

 

 

INCOME BEFORE INCOME TAXES

     66,349        19,232        155,051        132,020   

Income tax expense (benefit)

     64        (36     126        (25
  

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME

     66,285        19,268        154,925        132,045   

GENERAL PARTNER’S INTEREST IN NET INCOME

     205        60        479        409   
  

 

 

   

 

 

   

 

 

   

 

 

 

LIMITED PARTNERS’ INTEREST IN NET INCOME

   $ 66,080      $ 19,208      $ 154,446      $ 131,636   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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Table of Contents

STATEMENTS OF CASH FLOWS

(unaudited)

 

     Six Months Ended
June  30,
 
     2011     2010  

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES

   $ 233,152      $ 233,100   
  

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

    

MEP Transaction

            3,016   
  

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from borrowings

     20,000        30,376   

Principal payments on debt

     (20,000     (19,122

Distributions to partners

     (246,016     (241,524

Debt issuance costs

            (5,846
  

 

 

   

 

 

 

Net cash used in financing activities

     (246,016     (236,116
  

 

 

   

 

 

 

DECREASE IN CASH AND CASH EQUIVALENTS

     (12,864       

CASH AND CASH EQUIVALENTS, beginning of period

     27,247        62   
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS, end of period

   $ 14,383      $ 62   
  

 

 

   

 

 

 

 

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Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar amounts are in thousands)

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC on February 28, 2011. Additionally, Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”) electronically file certain documents with the SEC, including annual reports on Form 10-K and quarterly reports on Form 10-Q. The SEC file number for each registrant and company website address is as follows:

 

   

ETP — SEC File No. 1-11727; website address: www.energytransfer.com

 

   

Regency — SEC File No. 0-51757; website address: www.regencyenergy.com

The information on these websites is not incorporated by reference into this report.

Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part II — Other Information – Item 1A. Risk Factors” included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2010.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”), Energy Transfer Partners GP, L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency Energy Partners, L.P. (“Regency”), Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

OVERVIEW

Energy Transfer Equity, L.P. is a publicly traded Delaware limited partnership that directly and indirectly owns equity interests in ETP and Regency, both publicly traded master limited partnerships engaged in diversified energy-related services.

At June 30, 2011, our equity interests consisted of:

 

     General Partner Interest
(as a % of total
partnership interest)
    Incentive  Distribution
Rights

(“IDRs”)
    Common Units  

ETP

     1.6     100     50,226,967   

Regency

     1.9     100     26,266,791   

The principal sources of the Parent Company’s cash flow are its direct and indirect investments in limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements, distributions to its partners and holders of the Series A Convertible Preferred Units (the “Preferred Units”) and at ETE’s election, capital contributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency. The Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries.

The following is a brief description of our reportable segments:

 

   

Investment in ETP – ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arkansas, Arizona, Colorado, Louisiana, Mississippi, New Mexico, Utah and West Virginia and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas. ETP also holds a 70% interest in a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets in Texas, Louisiana and Mississippi. ETP is also one of the largest retail marketers of propane in the United States, serving more than one million customers across the country.

 

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Investment in Regency – Regency is a publicly traded Delaware limited partnership formed in 2005 engaged in the gathering, treating, processing, compressing and transportation of natural gas and NGLs. Regency focuses on providing midstream services in some of the most prolific natural gas production regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville and Marcellus shales as well as the Permian Delaware basin. Its assets are primarily located in Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma. Regency also holds a 30% interest in a joint venture that owns and operates natural gas liquids storage, fractionation and transportation assets in Texas, Louisiana and Mississippi.

Recent Developments

Pending Acquisition

On July 19, 2011, we entered into a Second Amended and Restated Plan of Merger (the “Second Amended SUG Merger Agreement”) with Sigma Acquisition Corporation, a Delaware corporation and our wholly-owned subsidiary (“Merger Sub”), and Southern Union Company (“SUG”), a Delaware corporation. The Second Amended Merger Agreement modifies certain terms of the Amended and Restated Agreement and Plan of Merger entered into by us, Merger Sub and SUG on July 4, 2011. Under the terms of the Second Amended SUG Merger Agreement, Merger Sub will merge with and into SUG, with SUG continuing as the surviving entity and becoming our wholly-owned subsidiary (the “SUG Merger”) subject to certain conditions to close. Pursuant to the Second Amended SUG Merger Agreement, we would acquire all of the outstanding shares of SUG in a transaction valued at $9.4 billion, including $5.7 billion in cash and ETE Common Units and $3.7 billion of existing SUG indebtedness. Stockholders of SUG may elect to exchange each share of SUG stock for either $44.25 in cash or 1.00 ETE Common Unit. The maximum cash component is 60% of the aggregate consideration and the common unit component can fluctuate between 40% and 50%. Elections in excess of either the cash or common unit limits will be subject to proration.

We have secured $3.7 billion in committed financing from Credit Suisse Securities (USA) LLC (“Credit Suisse”) to fund a portion of the cash consideration. Closing of this business combination is contingent upon several conditions, including regulatory approvals and a vote of SUG shareholders. We expect the transaction to close in the first quarter of 2012.

On July 19, 2011, ETP entered into an Amended Citrus Merger Agreement pursuant to which it is anticipated that SUG will cause the contribution to ETP of SUG’s 50% interest in Citrus Corp., which owns 100% of the Florida Gas Transmission (“FGT”) pipeline system, in exchange for approximately $1.895 billion in cash and $105 million of ETP Common Units, contemporaneous with the completion of the merger between SUG and us pursuant to the Second Amended SUG Merger Agreement as described in Note 3 to our consolidated financial statements. Citrus Corp is currently jointly owned by SUG and El Paso Corporation. The FGT pipeline system has a capacity of 3.0 billion cubic feet per day and supplied approximately 63% of the natural gas consumed in Florida for 2010. FGT’s primary customers are utilities with strong investment grade credit ratings. FGT’s long-term contracts with these high credit quality customers are expected to increase ETP’s fee-based revenue stream.

Lone Star

Lone Star NGL LLC (“Lone Star”), ETP’s and Regency’s recently acquired 70% and 30%, respectively, joint venture announced plans to construct a 100,000 Bbls/d fractionator in Mont Belvieu, Texas. Total cost of the fractionator is expected to be approximately $375 million and is expected to be in service by early 2013.

Lone Star also announced the construction of an approximate 530-mile NGL pipeline that extends from Winkler County in West Texas to a processing plant in Jackson County, Texas. In addition, Lone Star has secured capacity on ETP’s recently-announced NGL pipeline from Jackson County to Mont Belvieu, Texas. The project is expected to be completed in the first quarter of 2013 for an estimated cost of $700 million, which will be funded by contributions from ETP and Regency that are reflective of their ownership interests.

 

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Table of Contents

Eagle Ford Expansion

In June 2011, Regency entered into agreements to provide gas and condensate gathering services for a producer in the Eagle Ford Shale and to construct facilities to perform these services, including a wellhead gathering system, at an expected cost to Regency of approximately $450 million. Capital expenditures are expected to be incurred primarily over the next three years and will initially be funded under Regency’s revolving credit facility. The expansion is scheduled for completion by 2014.

Tiger Pipeline Expansion

ETP recently completed construction of the 400 MMcf/d expansion of its Tiger pipeline. The Tiger pipeline expansion was placed in service on August 1, 2011, bringing the total capacity of the Tiger pipeline to 2.4 Bcf/d.

Results of Operations

We accounted for our May 26, 2010 acquisition of Regency (the “Regency Transactions”) using the purchase method of accounting. As a result, we consolidated the results of Regency and its consolidated subsidiaries since May 26, 2010. Consequently, this Management’s Discussion and Analysis of Financial Condition and Results of Operations does not include the results of operations of Regency and its consolidated subsidiaries for periods prior to the Regency Transactions.

Consolidated Results

 

     Three Months Ended
June 30,
          Six Months Ended
June 30,
       
     2011     2010     Change     2011     2010     Change  

Revenues

   $ 1,974,906      $ 1,362,528      $ 612,378      $ 3,964,026      $ 3,234,509      $ 729,517   

Cost of products sold

     1,264,152        840,453        423,699        2,465,578        2,065,318        400,260   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin

     710,754        522,075        188,679        1,498,448        1,169,191        329,257   

Operating expenses

     222,717        179,745        42,972        443,413        350,493        92,920   

Depreciation and amortization

     148,530        98,035        50,495        287,786        184,366        103,420   

Selling, general and administrative

     78,946        65,038        13,908        142,445        116,147        26,298   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     260,561        179,257        81,304        624,804        518,185        106,619   

Interest expense, net of interest capitalized

     (181,517     (129,036     (52,481     (349,446     (250,707     (98,739

Equity in earnings of affiliates

     28,819        12,193        16,626        54,260        18,374        35,886   

Gains (losses) on disposal of assets

     (681     1,375        (2,056     (2,435     (489     (1,946

Gains (losses) on non-hedged interest rate derivatives

     1,883        (22,468     24,351        3,403        (36,892     40,295   

Impairment of investment in affiliate

            (52,620     52,620               (52,620     52,620   

Other, net

     2,811        (5,213     8,024        (9,715     (3,070     (6,645

Income tax expense

     (5,224     (4,053     (1,171     (15,127     (9,264     (5,863

Income from discontinued operations

            86        (86            86        (86
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 106,652      $ (20,479   $ 127,131      $ 305,744      $ 183,603      $ 122,141   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The discussion under “Parent Company Results” below analyzes the results of operations of the Parent Company for the periods presented, and the discussion under “Segment Operating Results” below analyzes the results of operations related to our reportable segments.

 

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Table of Contents

Parent Company Results

The Parent Company currently has no separate operating activities apart from those conducted by ETP, Regency and their respective subsidiaries and the principal sources of cash flow are distributions it receives from its direct and indirect investments in the limited partner and general partner interests of ETP and Regency.

The following summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:

 

     Three Months Ended
June 30,
          Six Months Ended
June 30,
       
     2011     2010     Change     2011     2010     Change  

Selling, general and administrative

   $ (12,037   $ (15,079   $ 3,042      $ (13,879   $ (17,415   $ 3,536   

Interest expense, net of interest capitalized

     (40,587     (20,210     (20,377     (81,526     (36,916     (44,610

Equity in earnings of affiliates

     120,626        75,362        45,264        267,268        221,740        45,528   

Losses on non-hedged interest rate derivatives

            (20,753     20,753               (35,177     35,177   

Other, net

     (1,653     (88     (1,565     (16,812     (212     (16,600

Selling, general and administrative. For the three and six months ended June 30, 2011 compared to the same period in the prior year, selling, general and administrative expense decreased primarily due to a decrease in acquisition-related costs. The three and six months ended June 30, 2011 reflected approximately $9.0 million in expenses incurred related to our pending acquisition of SUG (see “Recent Developments” above), while the three and six months ended June 30, 2010 reflect approximately $12.8 million in expenses incurred related to our acquisition of a controlling interest in Regency in May 2010.

Interest Expense. For the three and six months ended June 30, 2011 compared to the same period in the prior year, interest expense increased primarily due to the issuance of $1.8 billion aggregate principal amount of 7.5% senior notes in September 2010 the proceeds from which were used to repay all of the outstanding indebtedness under our then existing revolving credit facility and term loan facility, to fund the cost to terminate interest rate swaps, and for general partnership purposes. In addition, interest expense for the periods presented reflected distributions on the ETE Preferred Units issued by ETE in connection with the acquisition of a controlling interest in Regency in May 2010. Distributions on ETE Preferred Units were $6.0 million and $12.0 million for the three and six months ended June 30, 2011, respectively, compared to $2.4 million reflected in the three and six months ended June 30, 2010.

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in ETP and Regency. The Parent Company recorded equity in earnings of ETP of $116.1 million and $75.8 million for the three months ended June 30, 2011 and 2010, respectively, and $259.8 million and $222.2 million for the six months ended June 30, 2011 and 2010, respectively. An analysis of ETP’s results is included in “Segment Operating Results” below. The three and six months ended June 30, 2011 also reflect the equity in earnings from Regency of $4.5 million and $7.5 million; whereas, the three and six months ended June 30, 2010 include equity in losses of Regency of $0.5 million, which represents only the period subsequent to the Parent Company’s acquisition of a controlling interest in Regency on May 26, 2010.

Losses on Non-Hedged Interest Rate Derivatives. The Parent Company terminated its interest rate swaps that were not accounted for as hedges in September 2010 in connection with the issuance of $1.8 billion of senior notes. Prior to that settlement, changes in the fair value of and cash payments related to these swaps were recorded directly in earnings. For the three and six months ended June 30, 2011, we recorded unrealized losses on our interest rate swaps as a result of decreases in the relevant floating index rates during the period.

Other, net. Other expenses increased between periods primarily due to non-cash charges recorded to increase the carrying value of the preferred units that were issued by the Parent Company in connection with the acquisition of a controlling interest in Regency in May 2010.

 

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Table of Contents

Segment Operating Results

Our reportable segments reflect two reportable segments, which conduct their business exclusively in the United States of America, as follows:

 

   

Investment in ETP — Reflects the consolidated operations of ETP.

 

   

Investment in Regency — Reflects the consolidated operations of Regency.

Each of the respective general partners of ETP and Regency has separate operating managements and boards of directors. We control ETP and Regency through our ownership of their respective general partners. See further discussion of ETP and Regency’s operations in Note 1 to our consolidated financial statements.

We evaluate the performance of our operating segments based on net income. The following tables present the financial information by segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

Net income (loss) by segment is as follows:

 

     Three Months
Ended June 30,
          Six Months Ended
June 30,
       
     2011     2010     Change     2011     2010     Change  

Investment in ETP

   $ 156,616      $ 42,843      $ 113,773      $ 403,818      $ 282,954      $ 120,864   

Investment in Regency

     14,837        (4,895     19,732        29,142        (4,895     34,037   

Corporate and Other

     (56,413     (58,427     2,014        (118,828     (94,456     (24,372

Adjustments and Eliminations

     (8,388            (8,388     (8,388            (8,388
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 106,652      $ (20,479   $ 127,131      $ 305,744      $ 183,603      $ 122,141   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Investment in ETP

 

     Three Months Ended
June 30,
          Six Months Ended
June 30,
       
     2011     2010     Change     2011     2010     Change  

Revenues

   $ 1,628,095      $ 1,267,706      $ 360,389      $ 3,315,672      $ 3,139,687      $ 175,985   

Cost of products sold

     1,008,628        770,857        237,771        2,003,085        1,995,722        7,363   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin

     619,467        496,849        122,618        1,312,587        1,143,965        168,622   

Operating expenses

     189,302        169,533        19,769        377,791        340,281        37,510   

Depreciation and amortization

     104,972        83,877        21,095        200,936        167,153        33,783   

Selling, general and administrative

     54,774        44,255        10,519        100,306        93,009        7,297   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     270,419        199,184        71,235        633,554        543,522        90,032   

Interest expense, net of interest capitalized

     (116,466     (103,014     (13,452     (223,706     (207,976     (15,730

Equity in earnings of affiliates

     5,040        4,072        968        6,673        10,253        (3,580

Gains (losses) on disposal of assets

     (528     1,385        (1,913     (2,254     (479     (1,775

Gains on non-hedged interest rate derivatives

     2,111               2,111        3,890               3,890   

Impairment of investment in affiliate

            (52,620     52,620               (52,620     52,620   

Other, net

     1,823        (1,595     3,418        2,041        747        1,294   

Income tax expense

     (5,783     (4,569     (1,214     (16,380     (10,493     (5,887