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 September 30, 2010

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 and 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 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 November 3, 2010, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P. 222,941,172 Common Units

 

 

 


Table of Contents

 

FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Equity, L.P. and Subsidiaries

 

PART I — FINANCIAL INFORMATION

  

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

  

Condensed Consolidated Balance Sheets – September 30, 2010 and December 31, 2009

     1   

Condensed Consolidated Statements of Operations – Three and Nine Months Ended September  30, 2010 and 2009

     3   

Condensed Consolidated Statements of Comprehensive Income (Loss) – Three and Nine Months Ended September 30, 2010 and 2009

     4   

Condensed Consolidated Statement of Equity – Nine Months Ended September 30, 2010

     5   

Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2010 and 2009

     6   

Notes to Condensed Consolidated Financial Statements

     7   

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

     47   

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     64   

ITEM 4. CONTROLS AND PROCEDURES

     66   

PART II — OTHER INFORMATION

  

ITEM 1. LEGAL PROCEEDINGS

     68   

ITEM 1A. RISK FACTORS

     68   

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

     68   

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     68   

ITEM 4. [RESERVED]

  

ITEM 5. OTHER INFORMATION

     68   

ITEM 6. EXHIBITS

     69   

SIGNATURE

     71   

 

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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” or “the Partnership”) in periodic press releases and some oral statements of Energy Transfer Equity officials during presentations about the Partnership, include certain “forward-looking” statements. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect” “continue,” “estimate,” “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.

Actual results may differ materially from any results 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 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010, as well as “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission (“SEC”) on February 24, 2010.

Definitions

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

 

/d

   per day

Bbls

   barrels

Btu

   British thermal unit, an energy measurement. A therm factor is 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

Dth

   million British thermal units (“dekatherm”)

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

 

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

     September 30,
2010
    December 31,
2009
 
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 88,113      $ 68,315   

Marketable securities

     2,270        6,055   

Accounts receivable, net of allowance for doubtful accounts of $6,957 and $6,338 as of September 30, 2010 and December 31, 2009, respectively

     503,743        566,522   

Accounts receivable from related companies

     62,065        51,894   

Inventories

     281,509        389,954   

Exchanges receivable

     18,919        23,136   

Price risk management assets

     16,268        12,371   

Other current assets

     128,343        149,712   
                

Total current assets

     1,101,230        1,267,959   

PROPERTY, PLANT AND EQUIPMENT

     12,863,914        10,117,041   

ACCUMULATED DEPRECIATION

     (1,286,200     (1,052,566
                
     11,577,714        9,064,475   

ADVANCES TO AND INVESTMENTS IN AFFILIATES

     1,324,428        663,298   

LONG-TERM PRICE RISK MANAGEMENT ASSETS

     644          

GOODWILL

     1,592,203        775,094   

INTANGIBLES AND OTHER ASSETS, net

     1,255,128        389,683   
                

Total assets

   $ 16,851,347      $ 12,160,509   
                

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

     September 30,
2010
     December 31,
2009
 
LIABILITIES AND EQUITY      

CURRENT LIABILITIES:

     

Accounts payable

   $ 411,935       $ 359,176   

Accounts payable to related companies

     13,392         38,515   

Exchanges payable

     11,504         19,203   

Price risk management liabilities

     5,865         65,146   

Accrued and other current liabilities

     550,102         366,781   

Current maturities of long-term debt

     35,221         40,924   
                 

Total current liabilities

     1,028,019         889,745   

LONG-TERM DEBT, less current maturities

     8,800,057         7,750,998   

SERIES A CONVERTIBLE PREFERRED UNITS (Note 11)

     304,950           

LONG-TERM PRICE RISK MANAGEMENT LIABILITIES

     60,470         73,332   

OTHER NON-CURRENT LIABILITIES

     236,544         226,183   

COMMITMENTS AND CONTINGENCIES (Note 15)

     

PREFERRED UNITS OF SUBSIDIARY (Note 11)

     70,896           

EQUITY:

     

PARTNERS’ CAPITAL:

     

General Partner

     633         368   

Limited Partners:

     

Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding at September 30, 2010 and December 31, 2009, respectively)

     151,535         53,412   

Accumulated other comprehensive income (loss)

     12,231         (53,628
                 

Total partners’ capital

     164,399         152   

Noncontrolling interest

     6,186,012         3,220,099   
                 

Total equity

     6,350,411         3,220,251   
                 

Total liabilities and equity

   $ 16,851,347       $ 12,160,509   
                 

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)

 

     Three Months Ended September 30,     Nine Months Ended September 30,  
     2010     2009     2010     2009  

REVENUES:

        

Natural gas operations

   $ 1,380,029      $ 943,975      $ 3,827,506      $ 3,004,163   

Retail propane

     183,786        162,224        914,372        829,901   

Other

     23,992        23,650        80,438        77,449   
                                

Total revenues

     1,587,807        1,129,849        4,822,316        3,911,513   
                                

COSTS AND EXPENSES:

        

Cost of products sold — natural gas operations

     883,716        591,797        2,520,157        1,865,914   

Cost of products sold — retail propane

     104,533        80,232        519,796        378,524   

Cost of products sold — other

     6,856        6,119        20,470        18,842   

Operating expenses

     208,809        158,883        559,302        517,337   

Depreciation and amortization

     120,315        84,738        304,681        239,626   

Selling, general and administrative

     61,526        34,579        177,673        146,640   
                                

Total costs and expenses

     1,385,755        956,348        4,102,079        3,166,883   
                                

OPERATING INCOME

     202,052        173,501        720,237        744,630   

OTHER INCOME (EXPENSE):

        

Interest expense, net of interest capitalized

     (209,871     (120,100     (460,578     (341,050

Equity in earnings of affiliates

     22,349        9,581        40,723        11,751   

Gains (losses) on disposal of assets

     81        (1,088     (408     (1,333

Gains (losses) on non-hedged interest rate derivatives

     (31,966     (35,589     (68,858     24,373   

Allowance for equity funds used during construction

     12,432        30        18,039        18,618   

Impairment of investment in affiliate

                   (52,620       

Other, net

     1,866        4,235        (6,812     4,559   
                                

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)

     (3,057     30,570        189,723        461,548   

Income tax expense (benefit)

     2,093        (3,697     11,357        5,773   
                                

INCOME (LOSS) FROM CONTINUING OPERATIONS

     (5,150     34,267        178,366        455,775   

Income from discontinued operations

     324               410          
                                

NET INCOME (LOSS)

     (4,826     34,267        178,776        455,775   

Less: Net income (loss) attributable to noncontrolling interest

     10,511        (12,704     62,069        152,893   
                                

NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS

     (15,337     46,971        116,707        302,882   

GENERAL PARTNER’S INTEREST IN NET INCOME (LOSS)

     (48     147        361        938   
                                

LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)

   $ (15,289   $ 46,824      $ 116,346      $ 301,944   
                                

BASIC NET INCOME (LOSS) PER LIMITED PARTNER UNIT

   $ (0.07   $ 0.21      $ 0.52      $ 1.35   
                                

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING

     222,941,172        222,898,248        222,941,151        222,898,188   
                                

DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT

   $ (0.07   $ 0.21      $ 0.52      $ 1.35   
                                

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING

     222,941,172        222,898,248        222,941,151        222,898,188   
                                

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)

 

     Three Months Ended September 30,     Nine Months Ended September 30,  
     2010     2009     2010     2009  

Net income (loss)

   $ (4,826   $ 34,267      $ 178,776      $ 455,775   

Other comprehensive income (loss), net of tax:

        

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

     64,644        8,162        67,199        10,320   

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

     25,791        (27,663     30,291        (27,049

Change in value of available-for-sale securities

     (732     3,049        (3,785     6,757   
                                
     89,703        (16,452     93,705        (9,972
                                

Comprehensive income

     84,877        17,815        272,481        445,803   

Less: Comprehensive income (loss) attributable to noncontrolling interest

     32,197        (19,635     89,915        142,353   
                                

Comprehensive income attributable to partners

   $ 52,680      $ 37,450      $ 182,566      $ 303,450   
                                

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010

(Dollars in thousands)

(unaudited)

 

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

Balance, December 31, 2009

   $ 368      $ 53,412      $ (53,628   $ 3,220,099      $ 3,220,251   

Regency Transactions (See Notes 1 and 3)

     648        209,065               1,895,268        2,104,981   

Distributions to ETE partners

     (1,121     (361,165                   (362,286

Subsidiary distributions

                          (390,805     (390,805

Subsidiary units issued for cash

     415        133,587               1,352,861        1,486,863   

Tax effect of remedial income allocation from tax amortization of goodwill

                          (2,552     (2,552

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

            685               21,750        22,435   

Non-cash executive compensation

            19               919        938   

Other comprehensive income, net of tax

                   65,859        27,846        93,705   

Other

     (38     (414            (1,443     (1,895

Net income

     361        116,346               62,069        178,776   
                                        

Balance, September 30, 2010

   $ 633      $ 151,535      $ 12,231      $ 6,186,012      $ 6,350,411   
                                        

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

 

     Nine Months Ended September 30,  
     2010     2009  

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES

   $ 927,683      $ 721,421   
                

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Cash paid for acquisitions, net of cash acquired

     (323,705     (6,244

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

     (1,125,104     (703,461

Contributions in aid of construction costs

     12,048        5,251   

Advances to affiliates, net of repayments

     (44,968     (534,500

Proceeds from the sale of assets

     84,044        13,235   
                

Net cash used in investing activities

     (1,397,685     (1,225,719
                

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from borrowings

     2,927,042        2,337,441   

Principal payments on debt

     (3,133,678     (1,816,884

Subsidiary equity offering, net of issue costs

     1,486,863        578,924   

Distributions to partners

     (362,286     (351,037

Debt issuance costs

     (35,612     (7,639

Distributions to noncontrolling interests

     (390,805     (278,338

Other

     (1,724       
                

Net cash provided by financing activities

     489,800        462,467   
                

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     19,798        (41,831

CASH AND CASH EQUIVALENTS, beginning of period

     68,315        92,023   
                

CASH AND CASH EQUIVALENTS, end of period

   $ 88,113      $ 50,192   
                

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

 

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED 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 September 30, 2010, our equity interests consisted of:

 

     General Partner
Interest
    Incentive
Distribution
Rights
(“IDRs”)
    Common
Units
 

ETP

     1.8     100     50,226,967   

Regency

     2.0     100     26,266,791   

We acquired our equity interests in Regency in a series of transactions, which we refer to as the Regency Transactions, that were completed on May 26, 2010. In the Regency Transactions, we:

 

   

acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Series A Convertible Preferred Units (the “Preferred Units”) having an aggregate liquidation preference of $300.0 million,

 

   

acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”) (see Note 8), and an option to acquire an additional 0.1% interest in MEP, in exchange for the redemption by ETP of approximately 12.3 million ETP Common Units we previously owned, and

 

   

acquired 26.3 million Regency Common Units in exchange for our contribution of all of our interests in MEP, including the option to acquire an additional 0.1% interest, to Regency.

For additional information regarding the Regency Transactions, see Note 3.

The unaudited condensed consolidated financial statements of ETE presented herein for the three and nine month periods ended September 30, 2010 and 2009 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 interest in ETP and Regency.

The unaudited condensed consolidated financial statements include the results of Regency from May 26, 2010, the date ETE obtained control of Regency, through September 30, 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 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

 

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general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. 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 20 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 Delaware limited partnership that owns and operates a diversified portfolio of energy assets. ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, an interstate pipeline, natural gas gathering, processing and treating assets located in Texas, New Mexico, Arizona, Louisiana, Colorado and Utah, and three natural gas storage facilities located in Texas. ETP’s intrastate and interstate pipeline systems transport natural gas from several natural gas producing areas, including the Barnett Shale in the Fort Worth Basin in North Texas, the Bossier Sands in East Texas, the Permian Basin in West Texas and New Mexico, the San Juan Basin in New Mexico and other producing areas in South Texas and Central Texas. ETP’s gathering and processing operations are conducted in many of these same producing areas as well as in the Piceance and Uinta Basins in Colorado and Utah. ETP is also one of the largest retail marketers of propane in the United States, serving more than one million customers across the country.

 

   

Regency is a publicly-traded Delaware limited partnership, formed in 2005, engaged in the gathering, treating, processing, compressing and transporting of natural gas and NGLs. Regency provides these services through systems located in Louisiana, Texas, Arkansas, Pennsylvania and the mid-continent region of the United States, which includes Kansas, Colorado, and Oklahoma. Regency’s midstream assets are primarily located in well-established areas of natural gas production that have been characterized by long-lived, predictable reserves.

Preparation of Interim Financial Statements

The accompanying condensed consolidated balance sheet as of December 31, 2009, which has been derived from audited financial statements, and the unaudited interim financial statements and notes thereto of the Partnership, as of September 30, 2010 and for the three and nine months ended September 30, 2010 and 2009, 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 September 30, 2010, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2010 and 2009. The unaudited interim condensed 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, 2009, as filed with the SEC on February 24, 2010.

Certain prior period amounts have been reclassified to conform to the 2010 presentation. These reclassifications had no impact on net income or total equity.

 

2. ESTIMATES AND SIGNIFICANT ACCOUNTING POLICIES:

Use of 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.

 

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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 the midstream and intrastate transportation and storage 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, allowances for doubtful accounts, 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, estimates related to our unit-based compensation plans, deferred taxes, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

Significant Accounting Policies

As a result of the Regency Transactions on May 26, 2010, the following significant accounting policies changed as compared to the significant accounting policies described in our Form 10-K for the year ended December 31, 2009.

Revenue Recognition

In addition to the policy in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, Regency provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput and cash flow. Regency is responsible for the installation and ongoing operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. Revenues for compression services are recognized when the service is performed.

Preferred Equity

As discussed in Note 11, we issued Preferred Units in May 2010. Based on the rights associated with those securities, the Preferred Units are reflected as non-current liabilities on our condensed consolidated balance sheet, and distributions on these units are reflected in consolidated interest expense.

Regency also has outstanding convertible preferred units (the “Regency Preferred Units”), as discussed in Note 11, which were issued prior to the Regency Transactions. Based on the rights associated with those securities, the Regency Preferred Units are reflected as temporary equity on our condensed consolidated balance sheet, and distributions on these units are recorded as a reduction of the noncontrolling interest related to Regency.

 

3. ACQUISITIONS AND DISPOSITIONS:

Regency Transactions

On May 26, 2010, we completed the Regency Transactions as discussed in Note 1. As of September 30, 2010, we owned approximately 19% of Regency’s outstanding common units, and distributions that we receive from Regency provide us with diversified cash flows and enhance our ability to increase distributions over time by pursuing new growth opportunities.

We accounted for the Regency Transactions using the purchase method of accounting. The purchase price was $305.0 million, which was the fair value of the 3,000,000 Preferred Units exchanged in connection with the Regency Transactions.

 

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The following summarizes the assets acquired and liabilities assumed in the Regency Transactions, as well as the fair value of the noncontrolling interest in Regency:

 

Total current assets

   $ 189,502   

Property, plant and equipment (1)

     1,548,384   

Advances to and investments in affiliates

     739,164   

Goodwill

     789,789   

Intangible assets

     666,360   

Other assets

     37,693   
        
     3,970,892   
        

Total current liabilities

     192,788   

Long-term debt

     1,239,863   

Other long-term liabilities (2)

     57,517   

Regency convertible preferred units

     70,793   

Noncontrolling interest

     2,104,981   
        
     3,665,942   
        

Total consideration

     304,950   

Cash received

     23,995   
        

Total consideration, net of cash received

   $ 280,955   
        

 

  (1) Property, plant and equipment consists of the following:

 

Gathering and transmission systems (5 to 20 years), including capital leases of $3.0 million

   $ 471,169   

Compression equipment (10 to 30 years)

     745,838   

Gas plants and buildings (15 to 35 years)

     116,967   

Other property, plant and equipment (3 to 10 years)

     100,264   

Construction work-in-process

     114,146   
        

Property, plant and equipment

   $ 1,548,384   
        

 

  (2) Liabilities assumed include capital leases of $3.1 million.

See disclosure of the amount of Regency’s revenues and earnings included in the condensed consolidated statement of operations from the close of the acquisition through September 30, 2010 in Note 19.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the three and nine months ended September 30, 2010 and 2009 are presented as if the Regency Transactions had been completed on January 1, 2009. Actual results for the three months ended September 30, 2010 include Regency for the entire period.

 

     Three Months Ended September 30,      Nine Months Ended September 30,  
         2010             2009              2010              2009      

Revenues

   $ 1,587,807      $ 1,357,001       $ 5,325,977       $ 4,634,638   

Net income (loss)

     (4,826     13,132         219,180         567,834   

Net income (loss) attributable to partners

     (15,337     30,803         167,079         299,727   

Basic net income (loss) per Limited Partner unit

     (0.07     0.14         0.75         1.34   

Diluted net income (loss) per Limited Partner unit

     (0.07     0.14         0.75         1.34   

 

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The pro forma consolidated results of operations include adjustments to:

 

   

include the results of Regency for all periods presented;

 

   

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

 

   

adjust for one-time expenses related to the Regency Transactions; and

 

   

adjust for the relative change in ownership of ETP as a result of the transfer of MEP.

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.

Other Acquisitions

In March 2010, ETP purchased a natural gas gathering company, which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale for approximately $150.0 million in cash, excluding certain adjustments as defined in the purchase agreement. In connection with this transaction, ETP recorded customer contracts of $68.2 million and goodwill of $27.3 million. See further discussion at Note 6.

In September 2010, Regency completed its acquisition of Zephyr Gas Services, LLC, a Texas based field services company for approximately $193.3 million in cash. In connection with this transaction, Regency recorded intangible assets of $110.8 million and no goodwill.

Dispositions

In July 2010, Regency sold its East Texas gathering and processing assets to an affiliate of Tristream Energy LLC for approximately $70 million in cash. The net income from these assets is classified as discontinued operations in the condensed consolidated statements of operations from the date of the Regency Transactions to the date of the sale.

 

4. CASH, CASH EQUIVALENTS AND SUPPLEMENTAL CASH FLOW INFORMATION:

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.

 

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Net cash provided by operating activities is comprised of the following:

 

     Nine Months Ended September 30,  
         2010             2009      

Net income

   $ 178,776      $ 455,775   

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

    

Impairment of investment in affiliate

     52,620          

Payments for termination of Parent Company interest rate derivatives (see Note 16)

     (168,550       

Proceeds from termination of ETP interest rate derivatives (see Note 16)

     26,495          

Depreciation and amortization

     304,681        239,626   

Amortization of finance costs charged to interest

     13,299        11,623   

Non-cash unit-based compensation expense

     22,547        21,356   

Non-cash executive compensation expense

     938        938   

Losses on disposal of assets

     408        1,333   

Allowance for equity funds used during construction

     (18,039     (18,618

Distributions in excess of (less than) equity in earnings of affiliates, net

     71,026        (5,696

Other non-cash

     12,678        4,884   

Changes in operating assets and liabilities, net of effects of acquisitions

     430,804        10,200   
                

Net cash provided by operating activities

   $ 927,683      $ 721,421   
                

Non-cash investing and financing activities are as follows:

 

     Nine Months Ended September 30,  
         2010              2009      

NON-CASH INVESTING ACTIVITIES:

     

Accrued capital expenditures

   $ 83,834       $ 64,530   
                 

Gain from subsidiary issuances of common units to noncontrolling interests (recorded in partners’ capital)

   $ 343,714       $ 46,078   
                 

NON-CASH FINANCING ACTIVITIES:

     

Long-term debt assumed and non-compete agreement notes payable issued in acquisitions

   $ 1,240,481       $ 17,113   
                 

 

5. INVENTORIES:

Inventories consisted of the following:

 

     September 30,
2010
     December 31,
2009
 

Natural gas and NGLs, excluding propane

   $ 96,498       $ 157,103   

Propane

     57,018         66,686   

Appliances, parts and fittings and other

     127,993         166,165   
                 

Total inventories

   $ 281,509       $ 389,954   
                 

We utilize commodity derivatives to manage price volatility associated with our natural gas inventory and designate 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 condensed consolidated balance sheets and in cost of products sold in our condensed consolidated statements of operations.

 

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6. GOODWILL, INTANGIBLES AND OTHER ASSETS:

A net increase in goodwill of $817.1 million was recorded during the nine months ended September 30, 2010, primarily due to $789.8 million from the Regency Transactions. This additional goodwill is not expected to be deductible for tax purposes. In addition, ETP recorded $27.3 million from the acquisition of a natural gas gathering company, which is expected to be deductible for tax purposes. See further discussion of acquisitions in Note 3.

We recorded the following intangible assets in conjunction with the Regency Transactions:

 

Amortizable intangible assets:

  

Customer relationships, contracts and agreements (30 years)

   $ 600,860   

Trade names (20 years)

     65,500   
        

Total intangible and other assets acquired

   $ 666,360   
        

In connection with the acquisition a natural gas gathering company, ETP also recorded customer contracts of $68.2 million with useful lives of 46 years. In connection with the Zephyr acquisition, Regency recorded intangibles related to customer relationships of $110.8 million with useful lives of 20 years.

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

 

     September 30, 2010     December 31, 2009  
     Gross Carrying
Amount
     Accumulated
Amortization
    Gross Carrying
Amount
     Accumulated
Amortization
 

Amortizable intangible assets:

          

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

   $ 956,456       $ (77,762   $ 176,858       $ (58,761

Trade names (20 years)

     65,500         (1,092               

Noncompete agreements (3 to 15 years)

     21,592         (11,965     24,139         (12,415

Patents (9 years)

     750         (97     750         (35

Other (10 to 15 years)

     1,320         (464     478         (397
                                  

Total amortizable intangible assets

     1,045,618         (91,380     202,225         (71,608

Non-amortizable intangible assets — Trademarks

     76,086                75,825           
                                  

Total intangible assets

     1,121,704         (91,380     278,050         (71,608

Other assets:

          

Financing costs (3 to 30 years)

     133,319         (38,516     84,099         (34,702

Regulatory assets

     107,233         (13,476     101,879         (9,501

Other

     36,554         (310     41,466           
                                  

Total intangibles and other assets

   $ 1,398,810       $ (143,682   $ 505,494       $ (115,811
                                  

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

 

     Three Months Ended September 30,      Nine Months Ended September 30,  
     2010      2009      2010      2009  

Reported in depreciation and amortization

   $ 10,770       $ 6,243       $ 23,826       $ 15,935   
                                   

Reported in interest expense

   $ 6,980       $ 2,877       $ 13,625       $ 8,306   
                                   

 

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

 

Years Ending December 31:

      

2011

   $ 58,929   

2012

     55,344   

2013

     49,913   

2014

     48,903   

2015

     46,448   

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review goodwill and non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage, midstream and retail propane operations and as of December 31 for all others, including all of Regency’s reporting units. We have not completed our annual impairment tests for 2010 and have not recorded any impairments related to amortizable intangible assets during the nine months ended September 30, 2010.

 

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 long-term debt at September 30, 2010 was $9.86 billion and $8.84 billion, respectively. At December 31, 2009, the aggregate fair value and carrying amount of long-term debt was $8.25 billion and $7.79 billion, respectively.

We have marketable securities, commodity derivatives, interest rate derivatives and embedded derivatives in the Regency Preferred Units that are accounted for as assets and liabilities at fair value in our condensed 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 determined by a Monte Carlo simulation 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 September 30, 2010 and December 31, 2009 based on inputs used to derive their fair values:

 

     Fair Value Measurements at
September 30, 2010 Using
 
     Fair Value
Total
    Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
    Significant
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
 

Assets:

        

Marketable securities

   $ 2,270      $ 2,270      $      $   

Interest rate derivatives

     201               201          

Commodity derivatives:

        

Natural Gas:

        

Fixed Swaps/Futures

     41,656        36,992        4,664          

Options — Puts

     29,025               29,025          

NGLs — Forward Swaps

     9,542               9,542          

WTI Crude Oil

     2,505               2,505          
                                

Total commodity derivatives

     82,728        36,992        45,736          
                                

Total Assets

   $ 85,199      $ 39,262      $ 45,937      $   
                                

Liabilities:

        

Interest rate derivatives

   $ (16,307   $      $ (16,307   $   

Series A Convertible Preferred Units

     (304,950                   (304,950

Regency Preferred Units

     (44,918                   (44,918

Commodity derivatives:

        

Natural Gas:

        

Basic Swaps IFERC/NYMEX

     (1,153     (1,153              

Swing Swaps IFERC

     (937     (912     (25       

Options — Calls

     (1,576            (1,576       

WTI Crude Oil

     (877            (877       

NGLs — Forward Swaps

     (4,206            (4,206       
                                

Total commodity derivatives

     (8,749     (2,065     (6,684       
                                

Total Liabilities

   $ (374,924   $ (2,065   $ (22,991   $ (349,868
                                

 

     Fair Value Measurements at
December 31, 2009 Using
 
     Fair Value
Total
    Quoted Prices
in Active
Markets for
Identical Assets
and Liabilities
(Level 1)
    Significant
Observable
Inputs
(Level 2)
 

Assets:

      

Marketable securities

   $ 6,055      $ 6,055      $   

Commodity derivatives

     32,479        20,090        12,389   

Liabilities:

      

Commodity derivatives

     (8,016     (7,574     (442

Interest rate derivatives

     (138,036            (138,036
                        
   $ (107,518   $ 18,571      $ (126,089
                        

 

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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 nine months ended September 30, 2010:

 

Balance, December 31, 2009

   $   

Issuance of Series A Convertible Preferred Units

     304,950   

Subsidiary preferred units (recorded in connection with the Regency Transactions)

     48,633   

Net unrealized losses included in other income (expense)

     (3,715
        

Balance, September 30, 2010

   $ 349,868   
        

Prior to the Regency Transactions, ETP adjusted the investment in MEP to fair value based on the present value of expected future cash flows (Level 3), resulting in a nonrecurring fair value adjustment of $52.6 million. See Note 8.

 

8. INVESTMENTS IN AFFILIATES:

Midcontinent Express Pipeline LLC

Certain of our subsidiaries are party to an agreement with Kinder Morgan Energy Partners, L.P. (“KMP”) for a 50/50 joint development of the Midcontinent Express pipeline. Construction of the approximately 500-mile pipeline was completed and natural gas transportation service commenced August 1, 2009, on the pipeline from Delhi, Louisiana, to an interconnect with the Transco interstate natural gas pipeline near Butler, Alabama. Interim service began on the pipeline from Bennington, Oklahoma, to Delhi in April 2009.

On January 9, 2009, MEP filed an amended application to revise its initial transportation rates to reflect an increase in projected costs for the project; the amended application was approved by the Federal Energy Regulatory Commission (“FERC”) on March 25, 2009. In May 2010, MEP, the entity formed to construct, own and operate this pipeline, placed into service certain expansion facilities to increase the total capacity for the main segment of the pipeline from Bennington to an interconnect location with Columbia Gas Transmission, LLC near Waverly, Louisiana from 1.4 Bcf/d to 1.5 Bcf/d. In June 2010, MEP placed additional expansion facilities into service, further increasing the capacity for the main segment of the pipeline from Bennington to the interconnect with the Columbia Gas Transmission pipeline from 1.5 Bcf/d to 1.8 Bcf/d, and increasing the total capacity of the main segment of the pipeline from the interconnect with Columbia Gas Transmission’s pipeline to the Transco interstate natural gas pipeline near Butler, Alabama, from 1.0 Bcf/d to 1.2 Bcf/d.

In conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, in exchange for ETP’s redemption of approximately 12.3 million ETP Common Units that were previously held by the Parent Company. The Parent Company immediately contributed this 49.9% interest in MEP to Regency in exchange for approximately 26.3 million Regency Common Units. In addition to the 49.9% interest in MEP, the Parent Company also acquired an option to purchase ETP’s remaining 0.1% interest in MEP in May 2011, which the Parent Company also transferred to Regency.

In conjunction with this transfer, ETP recorded a non-cash charge of approximately $52.6 million during the nine months ended September 30, 2010 to reduce the carrying value of its interest in MEP to its estimated fair value.

The following table presents aggregated selected income statement data for ETP and Regency’s unconsolidated affiliate, MEP (on a 100% basis):

 

     Three Months Ended September 30,      Nine Months Ended September 30,  
         2010              2009              2010              2009      

Revenue

   $ 56,997       $ 38,157       $ 162,088       $ 48,463   

Operating income

     29,100         18,271         76,278         21,047   

Net income

     16,351         14,077         42,063         15,475   

As stated above, the Midcontinent Express pipeline was placed into service during 2009.

 

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RIGS Haynesville Partnership Co.

Regency owns a 49.99% interest in the RIGS Haynesville Partnership Co. joint venture (“HPC”), which, through its ownership of the Regency Intrastate Gas System (“RIGS”), delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450-mile intrastate pipeline system.

The following table presents selected income statement data for HPC (on a 100% basis):

 

     Three Months Ended September 30,     

Nine Months

Ended September 30,

    

From Inception
(March 18, 2009)

to September 30,

 
         2010              2009          2010      2009  

Revenue

   $ 49,409       $ 14,188       $ 128,973       $ 30,095   

Operating income

     30,507         8,486         74,923         12,935   

Net income

     30,366         9,018         74,640         14,079   

Fayetteville Express Pipeline LLC

ETP is party to an agreement with KMP for a 50/50 joint development of the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that will originate in Conway County, Arkansas, continue eastward through White County, Arkansas and terminate at an interconnect with Trunkline Gas Company in Panola County, Mississippi. In December 2009, Fayetteville Express Pipeline LLC (“FEP”), the entity formed to construct, own and operate this pipeline, received FERC approval of its application for authority to construct and operate this pipeline. In July 2010, FERC granted a rehearing of the December 2009 order and allowed FEP to include in its initial rate proposed allowance for funds used during construction that accrued prior to filing its application. The pipeline began interim service in October 2010 and is expected to be fully operational in December 2010. Upon completion of all facilities, the pipeline is expected to have an initial capacity of 2.0 Bcf/d. As of September 30, 2010, FEP has secured binding commitments for a minimum of 10 years for transportation of approximately 1.85 Bcf/d. The new pipeline will interconnect with Natural Gas Pipeline Company of America (“NGPL”) in White County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi and ANR Pipeline Company in Quitman County, Mississippi. NGPL is operated and partially owned by Kinder Morgan, Inc. Kinder Morgan, Inc. owns the general partner of KMP.

 

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9. NET INCOME (LOSS) PER LIMITED PARTNER UNIT:

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

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
             2010                     2009                      2010                     2009          

Basic Net Income (Loss) per Limited Partner Unit:

         

Limited Partners’ interest in net income (loss)

   $ (15,289   $ 46,824       $ 116,346      $ 301,944   
                                 

Weighted average Limited Partner units

     222,941,172        222,898,248         222,941,151        222,898,188   
                                 

Basic net income (loss) per Limited Partner unit

   $ (0.07   $ 0.21       $ 0.52      $ 1.35   
                                 

Diluted Net Income (Loss) per Limited Partner Unit:

         

Limited Partners’ interest in net income (loss)

   $ (15,289   $ 46,824       $ 116,346      $ 301,944   

Dilutive effect of equity-based compensation of subsidiaries

                    (158     (428
                                 

Diluted net income (loss) available to Limited Partners

   $ (15,289   $ 46,824       $ 116,188      $ 301,516   
                                 

Weighted average Limited Partner units

     222,941,172        222,898,248         222,941,151        222,898,188   
                                 

Diluted net income (loss) per Limited Partner unit

   $ (0.07   $ 0.21       $ 0.52      $ 1.35   
                                 

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

 

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10. DEBT OBLIGATIONS:

Our debt obligations consisted of the following:

 

     September 30,
2010
    December 31,
2009
 

Parent Company Indebtedness:

    

ETE Senior Notes

   $ 1,800,000      $   

ETE senior secured revolving credit facilities

            123,951   

ETE Senior Secured Term Loan

            1,450,000   

Subsidiary Indebtedness:

    

ETP Senior Notes

     5,050,000        5,050,000   

Regency Senior Notes

     607,500          

Transwestern Senior Unsecured Notes

     870,000        870,000   

HOLP Senior Secured Notes

     105,127        140,512   

ETP Revolving Credit Facility

            150,000   

Regency Revolving Credit Facility

     375,000          

HOLP Revolving Credit Facility

            10,000   

Other long-term debt

     8,434        10,288   

Unamortized premiums (discounts)

     554        (12,829

Fair value adjustments related to interest rate swaps

     18,663          
                
     8,835,278        7,791,922   

Current maturities

     (35,221     (40,924
                
   $ 8,800,057      $ 7,750,998   
                

 

Future maturities of long-term debt for each of the next five years and thereafter are as follows:

  

 

 

Years Ending December 31:

        

2010 (remainder)

   $ 3,094     

2011

     34,696     

2012

     423,006     

2013

     730,165     

2014

     818,656     

Thereafter

     6,806,444     
          

Total (1)

   $ 8,816,061     
          

 

  (1) Excludes $19.2 million in unamortized premiums, discounts and fair value adjustments related to interest rate swaps.

Senior Notes

In addition to the ETP Senior Notes disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009, we and our subsidiaries have the following notes outstanding.

ETE Senior Notes

In September 2010, the Parent Company completed a public offering of $1.8 billion aggregate principal amount of 7.5% Senior Notes due October 15, 2020. We used net proceeds of approximately $1.77 billion to repay all of the outstanding indebtedness under our then existing revolving credit facility and term loan facility, to fund the cost to terminate the interest rate swap agreements related to those borrowings, and for general partnership purposes. We may redeem some or all of the notes at any 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

Senior Notes due 2018. Subsequent to September 30, 2010, Regency completed a public offering of $600.0 million aggregate principal amount of its 6.875% Senior Notes due 2018. The sale of the notes closed on October 27, 2010 and Regency will use the net proceeds to fund the tender offer discussed below and to reduce outstanding borrowings under its revolving credit facility.

 

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Senior Notes due 2016. Regency has $250.0 million of senior notes that mature on June 1, 2016. The senior notes bear interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1. The carrying value of the senior notes as of September 30, 2010 was $256.3 million, including an unamortized premium related to the Regency Transactions of $6.3 million.

At any time before June 1, 2012, up to 35% of the senior notes can be redeemed with the proceeds of an equity offering at a price of 109.375% plus accrued interest. Beginning June 1, 2013, Regency may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, Regency may also redeem all or part of the notes at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined in the indenture governing the senior notes) as of such redemption date plus 0.50% over the principal amount of the note.

Senior Notes due 2013. Regency has $357.5 million senior notes that mature on December 15, 2013. The senior notes bear interest at 8.375% and interest is payable semi-annually in arrears on each June 15 and December 15. The carrying value of the senior notes as of September 30, 2010 was $364.0 million, including an unamortized premium related to the Regency Transactions of $6.5 million.

On October 13, 2010, Regency announced that it commenced a cash tender offer and consent solicitation for its outstanding 8.375% senior notes due 2013 (the “Tender Offer”). On October 27, 2010, Regency accepted for purchase approximately $271.1 million of its senior notes due 2013 pursuant to the Tender Offer. The Tender Offer will expire 8:00 a.m., New York City time, on November 10, 2010. Regency currently anticipates that it will call for redemption any senior notes due 2013 not purchased in the Tender Offer and will satisfy and discharge the indenture relating to the senior notes due 2013 in compliance with the terms of the notes, the indenture and applicable law; provided, however, that it may elect not to redeem such notes or satisfy and discharge the related indenture.

Upon a change of control, each of Regency’s senior notes may, at such Unitholder’s option, 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. Subsequent to the Regency Transactions, no noteholder has exercised this option.

Revolving Credit Facilities

ETE Senior Secured Revolving Credit Facilities

Concurrent with the closing of its senior notes offering in September 2010, the Parent Company terminated its $500 million senior secured revolving credit facility and entered into a $200 million five-year senior secured revolving credit facility (the “Parent Company Credit Agreement”) available through September 20, 2015. As of September 30, 2010, there were no outstanding borrowings under the Parent Company Credit Agreement.

Under the Parent Company Credit Agreement, the obligations of ETE are secured by all tangible and intangible assets of ETE and certain of its subsidiaries, including (i) its ownership of 50,226,967 ETP Common Units; (ii) ETE’s 100% equity interest in ETP LLC and ETP GP, through which ETE holds the incentive distribution rights in ETP; (iii) the 26,266,791 common units of Regency; (iv) ETE’s 100% membership interest in ETE GP Acquirer LLC (“ETE Acquirer”); and (v) ETE Acquirer’s 100% equity interest in the Regency GP and Regency LLC.

Borrowings bear interest, at ETE’s option, at either the Eurodollar rate plus an applicable margin or the alternative base rate. The alternative base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate, a federal funds effective rate plus 0.50%, and an adjusted one-month LIBOR rate plus 1.00%. The applicable margins are based upon ETE’s leverage ratio and range from 2.75% to 3.75% for Eurodollar loans and from 1.75% to 2.75% for base rate loans. The commitment fee payable on the unused portion of the Parent Company Credit Agreement is based on ETE’s leverage ratio and ranges from 0.50% to 0.75%.

 

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In connection with the Parent Company Credit Agreement, ETE and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of ETE’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and security interest in, all of ETE’s and the other grantors’ tangible and intangible assets.

ETP Credit Facility

ETP maintains a revolving credit facility (the “ETP Credit Facility”) that 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). Amounts borrowed under the ETP Credit Facility bear interest, at ETP’s option, at a Eurodollar rate plus an applicable margin or a base rate. The base rate used to calculate interest on base rate loans will be calculated using the greater of a prime rate or a federal funds effective rate plus 0.50%. The applicable margin for Eurodollar loans ranges from 0.30% to 0.70% based upon ETP’s credit rating and is currently 0.55% (0.60% if facility usage exceeds 50%). The commitment fee payable on the unused portion of the ETP Credit Facility varies based on ETP’s credit rating with a maximum fee of 0.125%. The fee is 0.11% based on ETP’s current rating.

As of September 30, 2010, there were no outstanding borrowings under the ETP Credit Facility. Taking into account letters of credit of approximately $22.4 million, the amount available for future borrowings was $1.98 billion.

Regency Credit Facility

Regency maintains its revolving credit facility (the “Regency Credit Facility”) through its subsidiary, Regency Gas Services LP (“RGS”). The Regency Credit Facility has aggregate revolving commitments of $900 million, with $200 million of availability for letters of credit. RGS also has the option to request an additional $250 million in revolving commitments with ten business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met. The maturity date of the Regency Credit Facility is June 15, 2014; however, the maturity date will be accelerated to June 15, 2013 if Regency’s senior notes due 2013 have not been redeemed or refinanced by that date.

The alternate base rate used to calculate interest on base rate loans will be calculated using the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.50%. The applicable margin shall range from 1.50% to 2.25% for base rate loans, 2.50% to 3.25% for Eurodollar loans, and a commitment fee will range from 0.375% to 0.500% based upon the consolidated leverage ratio of Regency. RGS must also pay a participation fee for each revolving lender participating in letters of credit based upon the applicable margin, which is currently 2.9% of the average daily amount of such lender’s letter of credit exposure, and a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of the letter of credit exposure.

As of September 30, 2010, there was a balance outstanding in the Regency Credit Facility of $375.0 million in revolving credit loans and approximately $16.0 million in letters of credit. The total amount available under the Regency Credit Facility, as of September 30, 2010, which is reduced by any letters of credit, was approximately $509.0 million. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 3.2%.

HOLP Credit Facility

Heritage Operating, L.P. (“HOLP”), a subsidiary of ETP, has a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available to HOLP through June 30, 2011, which may be expanded to $150.0 million. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined in the credit agreement for the HOLP Credit Facility, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration

 

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accounts of HOLP and the capital stock of HOLP’s subsidiaries secure the HOLP Credit Facility. At September 30, 2010, the HOLP Credit Facility had no outstanding balance in revolving credit loans and outstanding letters of credit of $0.5 million. The amount available for borrowing as of September 30, 2010 was $74.5 million.

Covenants Related to Our Credit Agreements

ETP has debt covenants disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009. Additionally, Regency has its own credit agreements and a brief description of the primary covenants in its credit agreements and our updated debt covenants is set forth below. We, ETP and Regency were in compliance with all requirements, tests, limitations, and covenants related to our respective debt agreements at September 30, 2010.

Covenants Related to ETE Senior Secured Credit Facility

The Parent Company Credit Agreement contains customary representations, warranties and covenants, including financial covenants regarding a maximum leverage ratio, a maximum consolidated leverage ratio, a minimum fixed charge coverage ratio and a minimum loan to value ratio. In addition, the Parent Company Credit Agreement contains customary events of default, including, but not limited to, (i) default for failure to pay the principal on any Loan or any reimbursement obligation with respect to any letter of credit when due and payable, (ii) failure to duly observe, perform or comply with certain specified covenants, (iii) a representation or warranty made in connection with any loan document proves to have been false or incorrect in any material respect on any date on or as of which made, and (iv) the occurrence of a change of control.

Covenants Related to the Regency Senior Notes

The Regency senior 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.

If the Regency senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to many of the foregoing covenants.

Covenants Related to the Regency Credit Facility

The Regency Credit Facility contains the following financial covenants:

 

   

Regency’s consolidated total leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.25 to 1.

 

   

Regency’s interest coverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not be less than 2.75 to 1.

 

   

Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3.00 to 1.

On May 26, 2010, in connection with the Regency Transactions, Regency amended the Regency Credit Facility to permit its acquisition of a 49.9% membership interest in MEP and to include the results of operations of MEP in the calculation of Regency’s compliance with these financial covenants.

 

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The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:

 

   

incur indebtedness;

 

   

grant liens;

 

   

enter into sale and leaseback transactions;

 

   

make certain investments, loans and advances;

 

   

dissolve or enter into a merger or consolidation;

 

   

enter into asset sales or make acquisitions;

 

   

enter into transactions with affiliates;

 

   

prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);

 

   

issue capital stock or create subsidiaries; or

 

   

engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.

 

11. REDEEMABLE PREFERRED UNITS

ETE Preferred Units

In connection with the Regency Transactions as discussed in Note 1, ETE issued 3,000,000 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 long-term liability in our condensed consolidated balance sheet as of September 30, 2010. The Preferred Units were issued in a private placement at a stated price of $100 per unit and are entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit. The Preferred Units will automatically convert on the fourth anniversary of the date of issuance into an amount of ETE Common Units equal in value to the issue price plus any accrued but unpaid distributions plus a specified premium equal to the lesser of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance of the Preferred Units. ETE may choose, at its sole option, to pay 50% of the conversion consideration based on the issue price plus any accrued but unpaid distributions in cash. ETE may elect to redeem all, but not less than all, of the Preferred Units beginning on the third anniversary of the date of issuance for ETE Common Units or cash equal to the issue price plus a premium paid out in common units, equal to the greater of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE Common Units subsequent to the date of issuance. GE EFS also has certain rights to force ETE to redeem or convert the outstanding Preferred Units for specified consideration upon the occurrence of certain extraordinary events involving ETE or ETP. Holders of the Preferred Units have no voting rights, except that approval of a majority of the Preferred Units is needed to approve any amendment to ETE’s Third Amended and Restated Agreement of Limited Partnership, as amended (the “Partnership Agreement”) that would result in (i) any increase in the size of the class of Preferred Units, (ii) any alteration or change to the rights, preferences, privileges, duties, or obligations of the Preferred Units or (iii) any other matter that would adversely affect the rights or preferences of the Preferred Units, including in relation to other classes of ETE partnership interests.

Regency Preferred Units

Regency has 4,371,586 Regency Preferred Units outstanding. As of September 30, 2010, the Regency Preferred Units were convertible into 4,584,192 Regency Common Units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions thereon. Holders of the Regency Preferred Units receive fixed Regency quarterly cash distributions of $0.445 per unit. Holders can elect to convert Regency Preferred Units to Regency Common Units at any time in accordance with Regency’s partnership agreement.

Upon a change in control, each unitholder may, at such holder’s option, require Regency to purchase the Regency Preferred Units for an amount equal to 101% of the total of the face value of the Regency Preferred Units plus all accrued but unpaid distributions thereon. Subsequent to the Regency Transactions, no unitholder has exercised this option.

 

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

 

     Regency
Preferred Units
     Amount (1)  

Balance at acquisition date

     4,371,586       $ 70,793   

Accretion to redemption value

             103   
                 

Ending balance as of September 30, 2010

     4,371,586       $ 70,896   
                 

 

  (1) This amount will be accreted to $80 million plus any accrued and unpaid distributions at September 2, 2029.

 

12. PARTNERS’ CAPITAL:

Common Units Issued

The change in ETE Common Units during the nine months ended September 30, 2010 was as follows:

 

     Number of
Units
 

Balance, December 31, 2009

     222,898,248   

Issuance of restricted common units under long-term incentive plans

     42,924   
        

Balance, September 30, 2010

     222,941,172   
        

Sale 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 issuance of units by ETP or Regency (excluding unit issuances to the Parent Company) as a capital transaction. If ETP or Regency issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether its investment has been impaired, in which case a provision would be reflected in the statement of operations. The Parent Company did not recognize any impairment related to the issuance of ETP or Regency Common Units during the nine months ended September 30, 2010.

As a result of ETP’s and Regency’s issuances and redemption of Common Units, we have recognized increases in partners’ capital of $343.7 million for the nine months ended September 30, 2010.

Sale of Common Units by ETP

In January 2010, ETP issued 9,775,000 ETP Common Units through a public offering for net proceeds of $423.6 million. In August 2010, ETP issued 10,925,000 Common Units through a public offering for net proceeds of $489.4 million. The proceeds from these offerings were used primarily to repay borrowings under the ETP Credit Facility and to fund capital expenditures related to pipeline projects.

On August 26, 2009, ETP entered into an Equity Distribution Agreement with UBS Securities LLC (“UBS”). Pursuant to this agreement, ETP may offer and sell from time to time through UBS, as their sales agent, ETP Common Units having an aggregate value of up to $300.0 million. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between ETP and UBS. Under the terms of this agreement, ETP may also sell ETP Common Units to UBS as principal for its own account at a price agreed upon at the time of sale. Any sale of ETP Common Units to UBS as principal would be pursuant to the terms of a separate agreement between ETP and UBS. During the nine months ended September 30, 2010, ETP issued 3,842,283 ETP Common Units pursuant to this agreement. The proceeds of approximately $174.1 million, net of commissions, were used for general partnership purposes. Approximately $40.6 million of ETP’s Common Units remain available to be issued under the agreement based on trades initiated through September 30, 2010.

 

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On May 26, 2010, in conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, in exchange for ETP’s redemption of 12,273,830 ETP Common Units that were previously held by the Parent Company (see Note 8).

Sale of Common Units by Regency

In August 2010, Regency issued 17,537,500 Regency Common Units through a public offering. The proceeds of $400.2 million from the offering were used primarily to repay borrowings under the Regency Credit Facility.

Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. 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.

Distributions paid by the Parent Company are summarized as follows:

 

Quarter Ended

  Record Date   Payment Date   Distribution per
Common Unit
 
December 31, 2009   February 8, 2010   February 19, 2010   $  0.54   
March 31, 2010   May 7, 2010   May 19, 2010     0.54   
June 30, 2010   August 9, 2010   August 19, 2010     0.54   

On October 28, 2010, the Parent Company announced the declaration of a cash distribution for the three months ended September 30, 2010 of $0.54 per Common Unit, or $2.16 annualized. This distribution will be paid on November 19, 2010 to Unitholders of record at the close of business on November 8, 2010.

The total amounts of distributions declared during the nine months ended September 30, 2010 and 2009 were as follows (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):

 

     Nine Months Ended September 30,  
     2010      2009  

Limited Partners

   $ 361,164       $ 355,523   

General Partner

     1,122         1,104   
                 

Total distributions declared

   $ 362,286       $ 356,627   
                 

ETP’s Quarterly Distributions of Available Cash

ETP is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner.

Distributions paid by ETP are summarized as follows:

 

Quarter Ended

  Record Date   Payment Date   Distribution per
Common Unit
 
December 31, 2009   February 8, 2010   February 15, 2010   $  0.89375   
March 31, 2010   May 7, 2010   May 17, 2010     0.89375   
June 30, 2010   August 9, 2010   August 16, 2010     0.89375   

On October 28, 2010, ETP declared a cash distribution for the three months ended September 30, 2010 of $0.89375 per Common Unit, or $3.575 annualized. This distribution will be paid on November 15, 2010 to Unitholders of record at the close of business on November 8, 2010.

 

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The total amounts of ETP distributions declared during the nine months ended September 30, 2010 and 2009 were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):

 

     Nine Months Ended September 30,  
     2010      2009  

Limited Partners:

     

Common Units

   $ 503,582       $ 460,132   

Class E Units

     9,363         9,363   

General Partner Interest

     14,634         14,626   

Incentive Distribution Rights

     279,823         256,530   
                 

Total distributions declared by ETP

   $ 807,402       $ 740,651   
                 

Regency’s Quarterly Distributions of Available Cash

Regency is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner.

Distributions paid by Regency are summarized as follows:

 

Quarter Ended

  Record Date   Payment Date   Distribution per
Common Unit
 
June 30, 2010   August 6, 2010   August 13, 2010   $  0.445   

On October 26, 2010, Regency declared a cash distribution for the three months ended September 30, 2010 of $0.445 per Common Unit, or $1.78 annualized. This distribution will be paid on November 12, 2010 to Unitholders of record at the close of business on November 5, 2010.

The total amounts of Regency distributions declared since the date of acquisition were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):

 

     Nine Months Ended September 30,  
     2010      2009  

Limited Partners

   $ 114,270       $   

General Partner Interest

     2,372           

Incentive Distribution Rights

     1,965           
                 

Total distributions declared by Regency

   $ 118,607       $   
                 

Accumulated Other Comprehensive Income (Loss)

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

 

     September 30,
2010
    December 31,
2009
 

Net gains on commodity related hedges

   $ 43,270      $ 1,991   

Net losses on interest rate hedges

            (56,210

Unrealized gains on available-for-sale securities

     1,157        4,941   

Noncontrolling interest

     (32,196     (4,350
                

Total AOCI, net of tax

   $ 12,231      $ (53,628
                

 

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13. UNIT-BASED COMPENSATION PLANS:

No significant activity has occurred with respect to the ETE Long-Term Incentive Plan or ETP’s unit-based compensation plans during the nine months ended September 30, 2010.

Regency has the following awards outstanding as of September 30, 2010:

 

   

286,850 Regency common unit options, all of which are exercisable, with a weighted average exercise price of $21.55 per unit option;

 

   

No Regency restricted (non-vested) common units; and

 

   

200,267 Regency phantom units, with a weighted average grant date fair value of $15.43 per phantom unit.

In conjunction with the Regency Transactions, certain of Regency’s then-outstanding phantom units converted to 252,630 Regency Common Units as a result of change-in-control provisions associated with the awards. Each of Regency’s outstanding phantom units as of September 30, 2010 is the economic equivalent of one Regency Common Unit and is accompanied by a Distribution Equivalent Right, entitling the holder to an amount equal to any cash distributions paid on Regency Common Units. The outstanding Regency phantom units will vest one-third on each March 15th through 2013.

Regency expects to recognize $2.9 million of compensation expense related to the Regency phantom units over a weighted average period of 2.5 years.

 

14. INCOME TAXES:

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

 

    Three Months Ended September 30,     Nine Months Ended September 30,  
            2010                     2009                     2010                     2009          

Current expense (benefit):

       

Federal

  $ (3,182   $ (88   $ (124   $ (5,195

State

    1,363        3,224        8,864        10,120   
                               

Total

    (1,819     3,136        8,740        4,925   
                               

Deferred expense (benefit):

       

Federal

    3,286        (6,394     2,257        1,299   

State

    626        (439     360        (451
                               

Total

    3,912        (6,833     2,617        848   
                               

Total income tax expense (benefit)

  $ 2,093      $ (3,697   $ 11,357      $ 5,773   
                               

Effective tax rate

    (68.47 %)      (12.09 %)      5.99     1.25
                               

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.

 

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

Regulatory Matters

In August 2009, ETP filed an application for FERC authority to construct and operate the Tiger pipeline. The application was approved in April 2010 and construction began in June 2010. Subject to regulatory approvals, we expect initial service on the Tiger pipeline to commence in the fourth quarter of 2010. In February 2010, ETP announced a 400 MMcf/d expansion of the Tiger pipeline. In June 2010, we filed an application requesting FERC authorization to construct, own and operate that expansion, which remains under review before the FERC.

 

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On September 29, 2006, Transwestern filed revised tariff sheets under Section 4(e) of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective on November 1, 2006. In April 2007, the FERC approved a Stipulation and Agreement of Settlement that resolved the primary components of the rate case. Transwestern’s tariff rates and fuel rates are now final for the period of the settlement. Transwestern Pipeline Company, LLC (“Transwestern”), a subsidiary of ETP, is required to file a new rate case no later than October 1, 2011.

Guarantees

MEP Guarantee

ETP has guaranteed 50% of the obligations of MEP under its senior revolving credit facility (the “MEP Facility”), with the remaining 50% of MEP Facility obligations guaranteed by KMP. Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions. Although ETP transferred substantially all of its interest in MEP on May 26, 2010, as discussed above in Note 1, ETP will continue to guarantee 50% of MEP’s obligations under this facility through the maturity of the facility in February 2011. Regency has agreed to indemnify ETP for any costs related to the guarantee of payments under this facility.

Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if its ownership percentage in MEP increases or decreases. The MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 0.15%. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets.

As of September 30, 2010, MEP had $82.2 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. Our contingent obligations with respect to the 50% guarantee of MEP’s outstanding borrowings and letters of credit were $41.1 million and $16.6 million, respectively, as of September 30, 2010. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 0.9%.

FEP Guarantee

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP has guaranteed 50% of the obligations of FEP under the FEP Facility, with the remaining 50% of FEP Facility obligations guaranteed by KMP. Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if its ownership percentage in FEP increases or decreases. The FEP Facility is available through May 11, 2012 and amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or Prime Rate. The commitment fee payable on the unused portion of the FEP Facility varies based on both ETP’s credit rating and that of KMP, with a maximum fee of 1.0%.

As of September 30, 2010, FEP had $847.0 million of outstanding borrowings issued under the FEP Facility. ETP’s contingent obligation with respect to our 50% guarantee of FEP’s outstanding borrowings was $423.5 million as of September 30, 2010. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 3.3%.

Commitments

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts. In addition, we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We have 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. We also have a contract to purchase not less than 90.0 million gallons of propane per year that expires in 2015. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

 

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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 $6.0 million for the three months ended September 30, 2010 and 2009. For the nine months ended September 30, 2010 and 2009, rental expense for operating leases totaled approximately $17.7 million and $17.5 million, respectively.

Future minimum lease commitments for leases are:

 

Years Ending December 31:

      

2010 (remainder)

   $ 14,999   

2011

     27,327   

2012

     25,095   

2013

     22,419   

2014

     20,668   

Thereafter

     224,538   

ETP’s propane operations have an agreement with a subsidiary of Enterprise GP Holdings L.P. (collectively “Enterprise”) (see Note 17) to supply a portion of its propane requirements. The agreement expired in March 2010; however, ETP’s propane operations executed a five year extension as of April 2010. The extension will continue until March 2015 and includes an option to extend the agreement for an additional year.

ETP and Regency have commitments to make capital contributions to joint ventures. For the joint ventures that ETP currently has interests in, it expects that future capital contributions will be between $10 million and $15 million, which ETP expects to contribute primarily during the last three months of 2010. In addition, Regency expects capital contributions will be $47 million during the last three months of 2010.

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.

FERC and Related Matters. On July 26, 2007, the FERC issued to ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of ETP’s index-priced physical gas purchases in the Houston Ship Channel. The FERC alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the NGA. The FERC alleged that ETP violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. The FERC also alleged that one of ETP’s intrastate pipelines violated various FERC regulations by, among other things, granting undue preferences in favor of an affiliate. In its Order and Notice, the FERC specified that it was seeking $69.9 million in disgorgement of profits, plus interest, and $82.0 million in civil penalties relating to these market manipulation claims. In February 2008, the FERC’s Enforcement Staff also recommended that the FERC pursue market manipulation claims related to ETP’s trading activities in October 2005 for November 2005 monthly deliveries, a period not previously covered by the FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month.

 

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On August 26, 2009, ETP entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against ETP and, on September 21, 2009, the FERC approved the settlement agreement without modification. The agreement resolves all outstanding FERC claims against ETP and provides that ETP make a $5.0 million payment to the federal government and establish a $25.0 million fund for the purpose of settling related third-party claims based on or arising out of the market manipulation allegation against ETP by those third parties that elect to make a claim against this fund, including existing litigation claims as well as any new claims that may be asserted against this fund. Pursuant to the settlement agreement, the FERC made no findings of fact or conclusions of law. In addition, the settlement agreement specifies that by executing the settlement agreement ETP does not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with ETP’s alleged conduct related to the FERC claims. The settlement agreement also requires ETP to maintain specified compliance programs and to conduct independent annual audits of such programs for a two-year period.

In September 2009, the FERC appointed an administrative law judge, or ALJ, to establish a process of potential claimants to make claims against the $25.0 million fund, to determine the validity of any such claims and to make a recommendation to the FERC relating to the application of this fund to any potential claimants. Pursuant to the process established by the ALJ, a number of parties submitted claims against this fund and, subsequent thereto, the ALJ made various determinations with respect to the validity of these claims, solely for purposes of participation in this fund allocation process, and the methodology for making payments from the fund to claimants. In June 2010, each claimant that had been allocated a payment amount from the fund by the ALJ was required to make a determination as to whether to accept the ALJ’s recommended payment amount from the fund, and all such claimants accepted their allocated payment amounts. In connection with accepting the allocated payment amount, each such claimant was required to waive and release all claims against ETP related to this matter.

In addition to the claims that were settled pursuant to the ALJ fund allocation process discussed above, ETP was a party in three legal proceedings that asserted contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006. In all three of these legal proceedings, we have received favorable rulings at the lower court and appellate court levels that have resulted in the dismissal of all claims made in these proceedings, and no further appeals or motions for rehearing may be pursued by the plaintiffs in these proceedings except with respect to one proceeding as to which the plaintiffs may seek review at the U.S. Supreme Court, which action we believe is unlikely to occur.

ETP is expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred. ETP records accruals for litigation and other contingencies whenever required by applicable accounting standards. Based on the terms of the settlement agreement with the FERC described above, ETP made the $5.0 million payment and established the $25.0 million fund in October 2009. The after-tax impact of the settlement was less than $30.0 million due to tax benefits resulting from the portion of the payment that is used to satisfy third party claims.

Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”), their parent companies and American Electric Power Corporation (“AEP”), were defendants in litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel storage facility (“Cushion Gas”). This litigation is referred to as the “Cushion Gas Litigation”. In 2004, ETC OLP (a subsidiary of ETP) acquired the HPL Entities from AEP, at which time AEP agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory (approximately $1.00 billion in the aggregate). The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters. On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the HPL Entities of approximately $347.3 million less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel storage facility. Based on the indemnification provisions of the Cushion Gas Litigation Agreement, ETP expects that it will be indemnified for any monetary damages awarded to B of A under this court decision.

Other Matters. In addition to those matters described above, 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

 

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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, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As of September 30, 2010 and December 31, 2009, accruals of approximately $10.4 million and $11.1 million, respectively, were recorded related to deductibles. 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 it is possible that the outcome of a particular matter will result in the payment of an amount in excess of the amount accrued for the matter. As our accrual amounts are non-cash, any cash payment of an amount in resolution of a particular matter would likely be made from cash from operations or borrowings. If cash payments to resolve a particular matter substantially exceed our accrual for such matter, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

No amounts have been recorded in our September 30, 2010 or December 31, 2009 condensed consolidated balance sheets for contingencies and current litigation matters, other than accruals related to environmental matters and deductibles.

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 natural gas pipeline, gathering, treating, compressing, blending and processing business. 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, it is possible 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, could result in substantial costs and liabilities. Accordingly, we have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the financial liability, which could result from such events. However, the risk of environmental or other damage is inherent in transporting, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products, as it is with other entities engaged in similar businesses.

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 our liability in proportion to other parties, improvements in clean-up 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, we believe that such costs will not have a material adverse effect on our financial position.

As of September 30, 2010 and December 31, 2009, accruals on an undiscounted basis of $12.3 million and $12.6 million, respectively, were recorded in our condensed 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, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for clean-up costs.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the clean-up activities include remediation of several compressor sites on the Transwestern system for historical contamination associated with polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible for recovery in rates.

 

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The total accrued future estimated cost of remediation activities expected to continue through 2018 is $8.3 million, which is included in the aggregate environmental accruals. Transwestern received FERC approval 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 potential 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.

Environmental regulations were recently modified for the U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures program. We are currently reviewing the impact to our operations and expect 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 we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

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. We have not been named as a potentially responsible party at any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our September 30, 2010 condensed consolidated balance sheet or our December 31, 2009 consolidated balance sheet. 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.

By March 2013, the Texas Commission on Environmental Quality is required to develop another plan to address the recent change in the ozone standard from 0.08 parts per million, or ppm, to 0.075 ppm and the EPA recently proposed lowering the standard even further, to somewhere in between 0.06 and 0.07 ppm. These efforts may result in the adoption of new regulations that may require additional nitrogen oxide emissions reductions.

ETP’s pipeline operations are subject to regulation by the U.S. Department of Transportation (“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 September 30, 2010 and 2009, $5.8 million and $9.3 million, respectively, of capital costs and $3.9 million and $3.6 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. For the nine months ended September 30, 2010 and 2009, $10.8 million and $24.6 million, respectively, of capital costs and $10.2 million and $12.6 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.

Our operations are also subject to the requirements of the federal Occupational Safety and Health Act, also known as 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

 

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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 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.

Regency Environmental Matters

In 2004, a Phase I environmental study was performed on certain of Regency’s assets located in West Texas. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. The aggregate potential environmental remediation costs at specific locations were estimated to range from $1.9 million to $3.1 million. No governmental agency has required Regency to undertake these remediation efforts. Regency believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, Regency acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10.0 million limit subject to certain deductibles. No claims have been made against Regency or under the policy. Unless a claim has been made on Regency that exceeds the limits of the insurance policy, Regency will not further report on this matter.

Regency Field Services LLC (“RFS”), one of Regency’s operating subsidiaries, currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”). The Plants each have groundwater contamination as a result of historical operations. At the time that RFS acquired the Plants from El Paso Field Services LP (“El Paso”), Kerr-McGee Corporation (“Kerr-McGee”) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants. In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain of Kerr-McGee’s environmental remediation obligations (including its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation. In January 2009, Tronox filed for Chapter 11 bankruptcy protection. RFS filed a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants. Tronox has thus far continued its remediation efforts at the Plants. RFS is seeking assignment of indemnity rights against Tronox from El Paso. Tronox filed a reorganization plan on July 7, 2010. The Plan calls for the creation of a trust fund environmental clean-up at the various sites where Tronox has an obligation. Tronox must file the Environmental Claims Settlement Agreement, which will set forth the amount of trust funds allocated to each site, 14 days prior to the confirmation hearing, the date for which has not yet been set.

 

16. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

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, we 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 the condensed consolidated balance sheets. In general, our subsidiaries use derivatives to eliminate market exposure and price risk within its operations as follows:

 

   

Derivatives are utilized in ETP’s midstream operations in order to mitigate price volatility in its marketing activities and manage fixed price exposure incurred from contractual obligations. Regency also enters into swap contracts for WTI crude oil in addition to NGLs and natural gas to reduce price volatility.

 

   

ETP uses derivative financial instruments in connection with its natural gas inventory at the Bammel storage facility by purchasing physical natural gas and then selling financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. ETP also uses derivatives in its intrastate transportation and storage operations to hedge the sales price of retention gas and hedge location price differentials related to the transportation of natural gas.

 

   

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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ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets, 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 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 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 accumulated other comprehensive income 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 condensed consolidated statement of operations.

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.

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 focus. 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.

 

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The following table details the outstanding commodity-related derivatives:

 

     September 30, 2010      December 31, 2009  
     Notional
Volume
    Maturity      Notional
Volume
    Maturity  

Mark-to-Market Derivatives

         

Natural Gas:

         

Basis Swaps IFERC/NYMEX (MMBtu)

     (33,870,000     2010-2011         72,325,000        2010-2011   

Swing Swaps IFERC (MMBtu)

     11,735,000        2010-2011         (38,935,000     2010   

Fixed Swaps/Futures (MMBtu)

     486,000        2010-2011         4,852,500        2010-2011   

Options — Puts (MMBtu)

     440,000        2010-2011         2,640,000        2010   

Options — Calls (MMBtu)

     (3,440,000     2010-2011         (2,640,000     2010   

Propane:

         

Forwards/Swaps (Gallons)

                    6,090,000        2010   

Natural Gas Liquids:

         

Forwards/Swaps (Barrels)

     348,000        2010                  

WTI Crude Oil:

         

Forwards/Swaps (Barrels)

     59,800        2010                  

Fair Value Hedging Derivatives

         

Natural Gas:

         

Basis Swaps IFERC/NYMEX (MMBtu)

     (10,060,000     2010-2011         (22,625,000     2010   

Fixed Swaps/Futures (MMBtu)

     (20,160,000     2010-2011         (27,300,000     2010   

Hedged Item — Inventory (MMBtu)

     20,160,000        2010         27,300,000        2010   

Cash Flow Hedging Derivatives

         

Natural Gas:

         

Basis Swaps IFERC/NYMEX (MMBtu)

     (4,445,000     2010-2011         (13,225,000     2010   

Fixed Swaps/Futures (MMBtu)

     (5,440,000     2010-2011         (22,800,000     2010   

Options — Puts (MMBtu)

     22,680,000        2011-2012                  

Options — Calls (MMBtu)

     (22,680,000     2011-2012                  

Propane:

         

Forwards/Swaps (Gallons)

     58,086,000        2010-2011         20,538,000        2010   

Natural Gas Liquids:

         

Forwards/Swaps (Barrels)

     1,359,340        2011-2012                  

WTI Crude Oil:

         

Forwards/Swaps (Barrels)

     249,295        2011-2012                  

We expect gains of $36.6 million related to 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.

 

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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 have previously managed a portion of our current and future interest rate exposures by utilizing interest rate swaps in order to achieve our desired mix of fixed and variable rate debt. ETP also utilizes interest rate swaps to lock in the rate on a portion of its anticipated debt issuances. Our subsidiaries have the following interest rate swaps outstanding as of September 30, 2010:

 

Entity

   Term    Notional
Amount
    

Type (1)

   Hedge
Designation
 

ETP

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

Regency

   April 2012      250,000      

Pay a fixed rate of 1.325% and receive

a floating rate

     Undesignated   

 

  (1) Floating rates are based on LIBOR.

In May and August 2010, ETP terminated interest rate swaps with total notional amounts of $750.0 million and $350.0 million, respectively, for proceeds of $15.4 million and $11.1 million, respectively. These swaps were designated as fair value hedges. In connection with the swap terminations, $9.7 million and $10.4 million of previously recorded fair value adjustments to hedged long-term debt will be amortized as a reduction of interest expense through February 2015 and July 2013, respectively. The unamortized balance remaining related to these swaps was $18.7 million as of September 30, 2010.

In August 2010, ETP de-designated $200.0 million of total notional amounts of forward-starting interest rate swaps previously designated as cash flow hedges. These swaps remain outstanding as of September 30, 2010, along with additional swaps with a total notional amount of $200.0 million entered into during the three months ended September 30, 2010.

In addition to interest rate swaps, ETP also periodically enters into interest rate swaptions that enable counterparties to exercise options to enter into interest rate swaps with ETP. Swaptions may be utilized when ETP’s targeted benchmark interest rate for anticipated debt issuance is not attainable at the time in the interest rate swap market. Upon issuance of a swaption, ETP receives a premium, which ETP recognizes over the term of the swaption to “Gains (losses) on non-hedged interest rate derivatives” in the condensed consolidated statements of operations. No swaptions were outstanding as of September 30, 2010. In October 2010, the Partnership sold a swaption with a notional amount of $100.0 million and maturity date of December 31, 2010 to enter into a swap that, if exercised, would lock in the rate on a portion of anticipated debt issuances.

In connection with ETE’s offering of senior notes in September 2010, ETE terminated interest rate swaps with an aggregate notional amount of $1.5 billion and recognized in interest expense $66.4 million of realized losses on terminated interest rate swaps that had been accounted for as cash flow hedges. In addition to the $66.4 million of realized losses on hedged interest rate swaps, ETE also paid $102.2 million to terminate non-hedged interest rate swaps. The $102.2 million of realized losses on non-hedged interest rate swaps had previously been recognized in net income and therefore the termination of the non-hedged swaps did not impact earnings. The total cash paid to terminate interest rate swaps was $168.6 million, including realized losses on hedged and non-hedged swaps.

 

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Derivative Summary

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of September 30, 2010 and December 31, 2009:

 

     Fair Value of Derivative Instruments  
     Asset Derivatives      Liability Derivatives  
     September 30,
2010
     December 31,
2009
     September 30,
2010
    December 31,
2009
 

Derivatives designated as hedging instruments:

          

Commodity derivatives (margin deposits)

   $ 57,648       $ 669       $ (1,732   $ (24,035

Commodity derivatives

     9,544         8,443         (4,725     (201

Interest rate derivatives

                            (61,879
                                  
     67,192         9,112         (6,457     (86,115
                                  

Derivatives not designated as hedging instruments:

          

Commodity derivatives (margin deposits)

     66,113         72,851         (59,654     (36,950

Commodity derivatives

     7,348         3,928         (564     (241

Interest rate derivatives

     201                 (16,307     (76,157

Embedded derivatives in Regency Preferred Units

                     (44,918       
                                  
     73,662         76,779         (121,443     (113,348
                                  

Total derivatives

   $ 140,854       $ 85,891       $ (127,900   $ (199,463
                                  

The commodity derivatives (margin deposits) are recorded in “Other current assets” on our condensed 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 condensed consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

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 enters into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

ETP utilizes master-netting agreements and have 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, and it 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 the condensed consolidated balance sheets. ETP had net deposits with counterparties of $58.7 million and $79.7 million as of September 30, 2010 and December 31, 2009, respectively.

 

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

 

     Change in Value Recognized in OCI on Derivatives
(Effective Portion)
 
         Three Months Ended    
September 30,
        Nine Months Ended    
September 30,
 
     2010     2009     2010     2009  

Derivatives in cash flow hedging relationships:

        

Commodity derivatives

   $ 36,035      $ (15,146   $ 60,992      $ (15,282

Interest rate derivatives

     (9,825     (12,451     (29,980     (12,289
                                

Total

   $ 26,210      $ (27,597   $ 31,012      $ (27,571
                                

 

     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
September  30,
    Nine Months Ended
September 30,
 
            2010     2009     2010     2009  

Derivatives in cash flow hedging relationships:

           

Commodity derivatives

     Cost of products sold       $ 6,780      $ (847   $ 19,153      $ 8,702   

Interest rate derivatives

     Interest expense         (70,812     (7,220     (86,697     (18,927
                                   

Total

      $ (64,032   $ (8,067   $ (67,544   $ (10,225
                                   
     Location of  Gain/(Loss)
Reclassified from
AOCI into Income
(Ineffective Portion)
     Amount of Gain/(Loss) Recognized in Income on
Ineffective Portion
 
            Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
                2010             2009         2010     2009  

Derivatives in cash flow hedging relationships:

           

Commodity derivatives

     Cost of products sold       $ 241      $ (95   $ 346      $ (95

Interest rate derivatives

     Interest expense                                
                                   

Total

      $ 241      $ (95   $ 346      $ (95
                                   
     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    
September 30,
        Nine Months Ended    
September 30,
 
            2010     2009     2010     2009  

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

           

Commodity derivatives

     Cost of products sold       $ 9,968      $ (20,909   $ 9,001      $ (8,411

Interest rate derivatives

     Interest expense                                
                                   

Total

      $ 9,968      $ (20,909   $ 9,001      $ (8,411
                                   

 

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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
September  30,
    Nine Months Ended
September  30,
 
              2010             2009             2010             2009      

Derivatives not designated as hedging instruments:

           

Commodity derivatives

   Cost of products sold    $ 3,219      $ 30,346      $ 3,762      $ 87,349   

Interest rate derivatives

  

Gains (losses) on non-hedged interest rate derivatives

     (31,966     (35,589     (68,858     24,373   

Embedded Derivatives

  

Other income (expenses)

     7,321               3,715          
                                   

Total

      $ (21,426   $ (5,243   $ (61,381   $ 111,722   
                                   

We recognized $0.8 million and $13.5 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 three months ended September 30, 2010 and 2009, respectively. We recognized $49.0 million and $32.7 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 nine months ended September 30, 2010 and 2009, respectively. For the three and nine months ended September 30, 2009, we recognized unrealized losses of $16.4 million and $3.9 million, respectively, on commodity derivatives and related hedged inventory in fair value hedging relationships. For the three and nine months ended September 30, 2010, we recognized an unrealized gain of $8.2 million and an unrealized loss of $35.3 million, respectively, on commodity derivatives and related hedged inventory in fair value hedging relationships.

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 exposure associated with a single counterparty.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution 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. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty performance.

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 condensed consolidated balance sheet and recognized in net income or other comprehensive income.

 

17. RELATED PARTY TRANSACTIONS:

The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. For the three and nine months ended September 30, 2010, the Parent Company received $2.5 million and $3.3 million from Regency related to these services. For the three months ended September 30, 2010 and 2009, the Parent Company paid $2.6 million and $0.1 million, respectively, to ETP related to these services. For the nine months ended September 30, 2010 and 2009, the Parent Company paid $3.7 million and $0.4 million, respectively, to ETP related to these services.

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

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 routinely buy and sell product with

 

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Enterprise. Regency sells natural gas and NGLs to, and incurs NGL processing fees with Enterprise. The following table presents sales to and purchase from Enterprise, including Regency transactions subsequent to May 26, 2010:

 

       Three Months Ended September 30,        Nine Months Ended September 30,  
       2010        2009        2010        2009  

ETP’s Natural Gas Operations:

                   

Sales

     $ 126,992         $ 118,272         $ 402,238         $ 283,346   

Purchases

       396           12,958           13,928           29,304   

Regency’s Natural Gas Operations:

                   

Sales

       53,620                     72,121             

Purchases

       1,890                     2,312             

ETP’s Propane Operations:

                   

Sales

       262           2,815           11,228           14,323   

Purchases

       58,642           44,022           276,821           220,245   

ETP’s propane operations purchase a portion of its propane requirements from Enterprise pursuant to an agreement that was extended until March 2015, and includes an option to extend the agreement for an additional year. As of December 31, 2009, ETP had forward mark-to-market derivatives for 6.1 million gallons of propane at a fair value asset of $3.3 million with Enterprise. All of these forward contracts were settled as of June 30, 2010. In addition, as of September 30, 2010 and December 31, 2009, a subsidiary engaged in retail propane operations had forward derivatives accounted for as cash flow hedges of 58.1 million and 20.5 million gallons of propane at a fair value asset of $5.7 million and $8.4 million, respectively, with Enterprise.

Under a master services agreement with HPC, Regency operates and provides all employees and services for the operation and management of HPC. Under this agreement, Regency receives $1.4 million monthly as a partial reimbursement of its general and administrative costs. Regency also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. The related party general administrative expenses reimbursed to Regency were $4.2 million for the three months ended September 30, 2010 and $5.6 million for the period from May 26, 2010 to September 30, 2010.

Regency’s contract compression operations provide contract compression services to HPC. HPC also provides transportation service to Regency. Regency had revenue of $5.6 million for the three months ended September 30, 2010 and $7.7 million for the period from May 26, 2010 to September 30, 2010 and cost of sales of $2.5 million for the three months ended September 30, 2010 and $4.3 million for the period from May 26, 2010 to September 30, 2010 with HPC.

 

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

 

     September 30,
2010
     December 31,
2009
 

Accounts receivable from related parties:

     

Enterprise:

     

ETP’s Natural Gas Operations

   $ 35,175       $ 47,005   

Regency’s Natural Gas Operations

     21,572           

ETP’s Propane Operations

     407         3,386   

Other

     4,911         1,503   
                 

Total accounts receivable from related parties:

   $ 62,065       $ 51,894   
                 

Accounts payable to related parties:

     

Enterprise:

     

ETP’s Natural Gas Operations

   $ 1,561       $ 3,518   

Regency’s Natural Gas Operations

     1,070           

ETP’s Propane Operations

     8,209         31,642   

Other

     2,552         3,355   
                 

Total accounts payable to related parties:

   $ 13,392       $ 38,515   
                 

ETP’s net imbalance payable from Enterprise was $32 thousand and $0.7 million as of September 30, 2010 and December 31, 2009, respectively. Regency’s net imbalance payable with Enterprise was $0.6 million as of September 30, 2010.

 

18. OTHER INFORMATION:

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

Other Current Assets

Other current assets consisted of the following:

 

     September 30,
2010
     December 31,
2009
 

Deposits paid to vendors

   $ 58,710       $ 79,694   

Prepaid and other

     69,633         70,018   
                 

Total other current assets

   $ 128,343       $ 149,712   
                 

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

 

     September 30,
2010
     December 31,
2009
 

Interest payable

   $ 142,790       $ 137,708   

Customer advances and deposits

     128,903         88,430   

Accrued capital expenditures

     55,013         46,134   

Accrued wages and benefits

     49,145         25,577   

Taxes other than income taxes

     81,995         23,294   

Income taxes payable

     4,867         3,154   

Other

     87,389         42,484   
                 

Total accrued and other current liabilities

   $ 550,102       $ 366,781   
                 

 

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19. REPORTABLE SEGMENTS:

As a result of the Regency Transactions in May 2010, our reportable segments were reevaluated and now 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 and its general partner, ETP GP.

 

   

Investment in Regency — Reflects the consolidated operations of Regency and its general partner, Regency GP.

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 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.

 

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

Three months ended September 30, 2010:

           

Revenues from external customers

   $ 1,290,644      $ 295,094       $      $ 2,069      $ 1,587,807   

Intersegment revenues

            1,794                (1,794     —     

Depreciation and amortization

     85,612        32,205         3,056        (558     120,315   

Interest expense, net of interest capitalized

     101,241        20,379         89,486        (1,235     209,871   

Equity in earnings of affiliates

     595        21,754                       22,349   

Income tax expense (benefit)

     1,993        450         (350            2,093   

Net income (loss)

     107,387        7,846         (120,059            (4,826

Three months ended September 30, 2009:

           

Revenues from external customers

   $ 1,129,596      $       $      $ 253      $ 1,129,849   

Intersegment revenues

                                    

Depreciation and amortization

     81,684                3,054               84,738   

Interest expense, net of interest capitalized

     101,503                18,597               120,100   

Equity in earnings of affiliates

     9,581                              9,581   

Income tax expense (benefit)

     (2,897             (800            (3,697

Net income (loss)

     72,456                (38,189            34,267   

Nine months ended September 30, 2010:

           

Revenues from external customers

   $ 4,430,331      $ 391,177       $      $ 808      $ 4,822,316   

Intersegment revenues

            2,691                (2,691       

Depreciation and amortization

     252,765        42,750         9,166               304,681   

Interest expense, net of interest capitalized

     309,217        28,460         126,409        (3,508     460,578   

Equity in earnings of affiliates

     10,848        29,875                       40,723   

Income tax expense (benefit)

     12,486        695         (1,824            11,357   

Net income (loss)

     390,341        2,951         (214,516            178,776   

 

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

Nine months ended September 30, 2009:

             

Revenues from external customers

   $ 3,911,513       $       $      $       $ 3,911,513   

Intersegment revenues

                                      

Depreciation and amortization

     230,461                 9,165                239,626   

Interest expense, net of interest capitalized

     284,228                 56,822                341,050   

Equity in earnings of affiliates

     11,751                                11,751   

Income tax expense (benefit)

     8,594                 (2,821             5,773   

Net income (loss)

     530,361                 (74,586             455,775   

 

     As of
September 30,
2010
    As of
December 31,
2009
 

Total assets:

    

Investment in ETP

   $ 11,714,331      $ 11,734,972   

Investment in Regency

     4,692,722          

Corporate and Other

     452,185        431,109   

Adjustments and Eliminations

     (7,891     (5,572
                

Total

   $ 16,851,347      $ 12,160,509   
                
     Nine Months Ended September 30,  
     2010     2009  

Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):

    

Investment in ETP

   $ 1,140,501      $ 642,459   

Investment in Regency (including $1.5 billion acquired in the Regency Transactions)

     1,741,298          
                

Total

   $ 2,881,799      $ 642,459   
                

 

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20. 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)

 

     September 30,
2010
     December 31,
2009
 
ASSETS      

CURRENT ASSETS:

     

Cash and cash equivalents

   $ 6,325       $ 62   

Accounts receivable from related companies

     393         97   

Other current assets

     1,093         1,287   
                 

Total current assets

     7,811         1,446   

ADVANCES TO AND INVESTMENTS IN AFFILIATES

     2,249,788         1,711,928   

INTANGIBLES AND OTHER ASSETS, net

     29,522         5,574   
                 

Total assets

   $ 2,287,121       $ 1,718,948   
                 
LIABILITIES AND PARTNERS’ CAPITAL      

CURRENT LIABILITIES:

     

Accounts payable

   $ 143       $ 178   

Accounts payable to related companies

     6,663         5,024   

Price risk management liabilities

             64,704   

Accrued and other current liabilities

     10,966         1,607   
                 

Total current liabilities

     17,772         71,513   

LONG-TERM DEBT, less current maturities

     1,800,000         1,573,951   

SERIES A CONVERTIBLE PREFERRED UNITS

     304,950           

LONG-TERM PRICE RISK MANAGEMENT LIABILITIES

             73,332   

COMMITMENTS AND CONTINGENCIES

     

PARTNERS’ CAPITAL:

     

General Partner

     633         368   

Limited Partners – Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding at September 30, 2010 and December 31, 2009, respectively)

     151,535         53,412   

Accumulated other comprehensive income (loss)

     12,231         (53,628
                 

Total partners’ capital

     164,399         152   
                 

Total liabilities and partners’ capital

   $ 2,287,121       $ 1,718,948   
                 

 

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STATEMENTS OF OPERATIONS

(unaudited)

 

     Three Months Ended September 30,     Nine Months Ended
September  30,
 
     2010     2009     2010     2009  

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES

   $ (2,920   $ (786   $ (20,335   $ (3,608

OTHER INCOME (EXPENSE):

        

Interest expense

     (89,484     (18,589     (126,400     (56,728

Equity in earnings of affiliates

     102,388        82,661        324,128        370,195   

Losses on non-hedged interest rate derivatives

     (18,211     (17,348     (53,388     (7,954

Other, net

     (6,736     957        (6,949     329   
                                

INCOME (LOSS) BEFORE INCOME TAXES

     (14,963     46,895        117,056        302,234   

Income tax (expense) benefit

     (374     76        (349     648   
                                

NET INCOME (LOSS)

     (15,337     46,971        116,707        302,882   

GENERAL PARTNER’S INTEREST IN NET INCOME (LOSS)

     (48     147        361        938   
                                

LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)

   $ (15,289   $ 46,824      $ 116,346      $ 301,944   
                                

 

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STATEMENTS OF CASH FLOWS

(unaudited)

 

     Nine Months Ended
September 30,
 
     2010     2009  

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES

   $ 175,126      $ 349,402   
                

CASH FLOWS FROM INVESTING ACTIVITIES:

    

MEP Transaction

     3,016          
                

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from borrowings

     1,850,245        50,406   

Principal payments on debt

     (1,624,374     (48,771

Distributions to Partners

     (362,286     (351,037

Debt issuance costs

     (35,464       
                

Net cash used in financing activities

     (171,879     (349,402
                

INCREASE IN CASH AND CASH EQUIVALENTS

     6,263          

CASH AND CASH EQUIVALENTS, beginning of period

     62        62   
                

CASH AND CASH EQUIVALENTS, end of period

   $ 6,325      $ 62   
                

 

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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, 2009 filed with the SEC on February 24, 2010. 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 “Item 1A. Risk Factors” included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009.

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.

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 September 30, 2010, our equity interests consisted of:

 

     General Partner
Interest
    IDRs     Common
Units
 

ETP

     1.8     100     50,226,967   

Regency

     2.0     100     26,266,791   

The principal sources of historical cash flow have been distributions we receive from our direct and indirect investments in limited and general partner interests of ETP. Distributions that we receive from Regency provide us with diversified cash flows and enhance our ability to increase distributions over time by pursuing new growth opportunities. The Parent Company’s primary cash requirements are for distributions to its partners and holders of the Preferred Units, general and administrative expenses, and debt service. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP, Regency or their respective subsidiaries.

We acquired our equity interests in Regency in a series of transactions, which we refer to as the Regency Transactions, that were completed on May 26, 2010. In the Regency Transactions, we:

 

   

acquired the general partner interest and IDRs in Regency in exchange for 3,000,000 Series A Convertible Preferred Units having an aggregate liquidation preference of $300.0 million;

 

   

acquired from ETP an indirect 49.9% interest in Midcontinent Express Pipeline LLC (“MEP”), ETP’s joint venture with Kinder Morgan Energy Partners, L.P. (“KMP”) to operate the Midcontinent Express Pipeline, and an option to acquire an additional 0.1% interest in MEP in exchange for the redemption by ETP of approximately 12.3 million ETP Common Units we previously owned; and

 

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acquired 26.3 million Regency Common Units in exchange for our contribution of all of our interests in MEP, including the option to acquire an additional 0.1% interest, to Regency.

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

 

 

ETP is a publicly-traded Delaware limited partnership that owns and operates a diversified portfolio of energy assets. ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, an interstate pipeline, natural gas gathering, processing and treating assets located in Texas, New Mexico, Arizona, Louisiana, Colorado and Utah, and three natural gas storage facilities located in Texas. ETP’s intrastate and interstate pipeline systems transport natural gas from several natural gas producing areas, including the Barnett Shale in the Fort Worth Basin in North Texas, the Bossier Sands in East Texas, the Permian Basin in West Texas and New Mexico, the San Juan Basin in New Mexico and other producing areas in South Texas and Central Texas. ETP’s gathering and processing operations are conducted in many of these same producing areas as well as in the Piceance and Uinta Basins in Colorado and Utah. ETP is also one of the largest retail marketers of propane in the United States, serving more than one million customers across the country.

 

 

Regency is a publicly-traded Delaware limited partnership, formed in 2005, engaged in the gathering, treating, processing, compressing and transporting of natural gas and NGLs. Regency provides these services through systems located in Louisiana, Texas, Arkansas, Pennsylvania and the mid-continent region of the United States, which includes Kansas, Colorado, and Oklahoma. Regency’s midstream assets are primarily located in well-established areas of natural gas production that have been characterized by long-lived, predictable reserves.

Results of Operations

We accounted for 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 September 30,           Nine Months Ended September 30,        
     2010     2009     Change     2010     2009     Change  

Revenues

   $ 1,587,807      $ 1,129,849      $ 457,958      $ 4,822,316      $ 3,911,513      $ 910,803   

Cost of products sold

     995,105        678,148        316,957        3,060,423        2,263,280        797,143   
                                                

Gross margin

     592,702        451,701        141,001        1,761,893        1,648,233        113,660   

Operating expenses

     208,809        158,883        49,926        559,302        517,337        41,965   

Depreciation and amortization

     120,315        84,738        35,577        304,681        239,626        65,055   

Selling, general and administrative

     61,526        34,579        26,947        177,673        146,640        31,033   
                                                

Operating income

     202,052        173,501        28,551        720,237        744,630        (24,393

Interest expense, net of interest capitalized

     (209,871     (120,100     (89,771     (460,578     (341,050     (119,528

Equity in earnings of affiliates

     22,349        9,581        12,768        40,723        11,751        28,972   

Gains (losses) on disposal of assets

     81        (1,088     1,169        (408     (1,333     925   

Gains (losses) on non-hedged interest rate derivatives

     (31,966     (35,589     3,623        (68,858     24,373        (93,231

Allowance for equity funds used during construction

     12,432        30        12,402        18,039        18,618        (579

Impairment of investment in affiliate

                          (52,620            (52,620

Other, net

     1,866        4,235        (2,369     (6,812     4,559        (11,371

Income tax (expense) benefit

     (2,093     3,697        (5,790     (11,357     (5,773     (5,584

Income from discontinued operations

     324               324        410               410   
                                                

Net income

   $ (4,826   $ 34,267      $ (39,093   $ 178,776      $ 455,775      $