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 February 28, 2007

OR

 

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

For the Transition Period from              to             

Commission file number 001-32740

 


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.)

2828 Woodside StreetDallas, Texas 75204

(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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (check one).

Large accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  x

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 April 11, 2007, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P.        222,830,270 Common Units

 



Table of Contents

FORM 10-Q

TABLE OF CONTENTS

Energy Transfer Equity, L.P. and Subsidiaries

 

         Page

PART I      FINANCIAL INFORMATION

  

ITEM 1.      FINANCIAL STATEMENTS (Unaudited)

  

Condensed Consolidated Balance Sheets – February 28, 2007 and August 31, 2006

   1

Condensed Consolidated Statements of Operations – Three and Six Months Ended February 28, 2007 and 2006

   3

Consolidated Statements of Comprehensive Income (Loss) – Three and Six Months Ended February 28, 2007 and 2006

   4

Consolidated Statement of Partners’ Capital (Deficit) – Six Months Ended February 28, 2007

   5

Condensed Consolidated Statements of Cash Flows – Six Months Ended February 28, 2007 and 2006

   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

   67

ITEM 4.      CONTROLS AND PROCEDURES

   69

PART II     OTHER INFORMATION

  

ITEM 1.      LEGAL PROCEEDINGS

   69

ITEM 1A.   RISK FACTORS

   69

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

   72

ITEM 3.      DEFAULTS UPON SENIOR SECURITIES

   72

ITEM 4.      SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

   72

ITEM 5.      OTHER INFORMATION

   72

ITEM 6.      EXHIBITS

   72
SIGNATURES   

 

i


Table of Contents

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P., (“Energy Transfer Equity” 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 within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although the Partnership believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that every objective will be reached.

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, difficult to predict, and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2006 filed with the Securities and Exchange Commission on November 29, 2006.

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
Dekatherm    million British thermal units. 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.
Mcf    thousand cubic feet
MMBtu    million British thermal unit
MMcf    million cubic feet
Bcf    billion cubic feet
NGL    natural gas liquid, such as propane, butane and natural gasoline
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.

 

ii


Table of Contents

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

     February 28,
2007
   August 31,
2006
ASSETS      

CURRENT ASSETS:

     

Cash and cash equivalents

   $ 90,073    $ 26,204

Marketable securities

     4,026      2,817

Accounts receivable, net of allowance for doubtful accounts

     717,957      675,545

Inventories

     194,690      387,140

Deposits paid to vendors

     32,970      87,806

Exchanges receivable

     38,185      23,221

Price risk management assets

     18,616      56,851

Prepaid expenses and other

     38,507      43,151
             

Total current assets

     1,135,024      1,302,735

PROPERTY, PLANT AND EQUIPMENT, net

     5,526,350      3,748,614

GOODWILL

     751,992      633,998

INTANGIBLES AND OTHER LONG-TERM ASSETS, net

     373,867      238,794
             

Total assets

   $ 7,787,233    $ 5,924,141
             

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

 

1


Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

 

     February 28,
2007
    August 31,
2006
 
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)     

CURRENT LIABILITIES:

    

Accounts payable

   $ 533,493     $ 603,527  

Exchanges payable

     38,526       24,722  

Customer advances and deposits

     47,101       108,836  

Accrued and other current liabilities

     246,217       206,177  

Price risk management liabilities

     20,139       36,918  

Current maturities of long-term debt

     40,587       40,607  
                

Total current liabilities

     926,063       1,020,787  

LONG-TERM DEBT, less current maturities

     4,914,625       3,205,646  

DEFERRED INCOME TAXES

     204,075       207,877  

OTHER NON-CURRENT LIABILITIES

     25,557       4,953  

MINORITY INTERESTS

     1,905,490       1,439,127  

COMMITMENTS AND CONTINGENCIES

    
                
     7,975,810       5,878,390  
                

PARTNERS’ CAPITAL (DEFICIT):

    

General Partner

     91       (69 )

Limited Partners:

    

Common Unitholders (215,300,501 and 124,360,520 units authorized, issued and outstanding at February 28, 2007 and August 31, 2006, respectively)

     (250,817 )     (9,586 )

Class B Unitholders (2,521,570 units authorized, issued and outstanding)

     53,715       53,130  
                
     (197,011 )     43,475  

Accumulated other comprehensive income, per accompanying statements

     8,434       2,276  
                

Total partners’ capital (deficit)

     (188,577 )     45,751  
                

Total liabilities and partners’ capital (deficit)

   $ 7,787,233     $ 5,924,141  
                

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

 

2


Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)

 

     Three Months Ended
February 28,
    Six Months Ended
February 28,
 
     2007     2006     2007     2006  

REVENUES:

        

Midstream and transportation and storage

   $ 1,492,838     $ 2,083,303     $ 2,555,282     $ 4,291,837  

Propane and other

     569,642       366,513       895,643       574,599  
                                

Total revenues

     2,062,480       2,449,816       3,450,925       4,866,436  
                                

COSTS AND EXPENSES:

        

Cost of products sold, midstream and transportation and storage

     1,138,709       1,785,053       2,022,692       3,744,422  

Cost of products sold, propane and other

     347,107       223,778       550,467       355,036  

Operating expenses

     133,809       99,696       266,190       202,367  

Depreciation and amortization

     48,415       32,070       85,279       62,037  

Selling, general and administrative

     42,589       85,506       71,359       110,995  
                                

Total costs and expenses

     1,710,629       2,226,103       2,995,987       4,474,857  
                                

OPERATING INCOME

     351,851       223,713       454,938       391,579  

OTHER INCOME (EXPENSE):

        

Interest expense, net of interest capitalized

     (65,077 )     (39,096 )     (133,624 )     (78,239 )

Loss on extinguishment of debt

     —         (5,060 )     —         (5,060 )

Equity in earnings (losses) of affiliates

     (514 )     106       4,373       (168 )

Gain (loss) on disposal of assets

     (3,229 )     662       (1,285 )     534  

Interest and other income, net

     1,652       2,432       3,169       3,496  
                                

INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS

     284,683       182,757       327,571       312,142  

Income tax expense

     2,576       3,289       5,449       24,976  
                                

INCOME BEFORE MINORITY INTERESTS

     282,107       179,468       322,122       287,166  

Minority interests

     (134,751 )     (155,033 )     (143,726 )     (223,130 )
                                

NET INCOME

     147,356       24,435       178,396       64,036  

GENERAL PARTNER’S INTEREST IN NET INCOME

     467       144       612       392  
                                

LIMITED PARTNERS’ INTEREST IN NET INCOME

   $ 146,889     $ 24,291     $ 177,784     $ 63,644  
                                

BASIC NET INCOME PER LIMITED PARTNER UNIT

   $ 0.67     $ 0.18     $ 0.96     $ 0.54  
                                

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING

     217,821,530       131,468,542       186,054,317       118,826,222  
                                

DILUTED NET INCOME PER LIMITED PARTNER UNIT

   $ 0.67     $ 0.18     $ 0.95     $ 0.53  
                                

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING

     217,821,530       31,468,542       186,054,317       18,826,222  
                                

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

 

3


Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)

 

     Three Months Ended
February 28,
    Six Months Ended
February 28,
 
     2007     2006     2007     2006  

Net income

   $ 147,356     $ 24,435     $ 178,396     $ 64,036  

Other comprehensive income, net of tax:

        

Reclassification adjustment for gains and losses on derivative instruments accounted for as cash flow hedges included in net income

     (122,330 )     (142,002 )     (122,781 )     (42,150 )

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

     78,546       138,097       131,752       164,643  

Change in value of available-for-sale securities

     1,421       254       1,202       123  

Minority interests

     27,600       2,922       (4,015 )     (84,097 )
                                

Comprehensive income

   $ 132,593     $ 23,706     $ 184,554     $ 102,555  
                                

Reconciliation of Accumulated Other Comprehensive Income (Loss)

        

Balance, beginning of period

   $ 23,197     $ 12,555     $ 2,276     $ (26,693 )

Current period reclassification to earnings

     (122,330 )     (142,002 )     (122,781 )     (42,150 )

Current period change in value

     79,967       138,351       132,954       164,766  

Minority interests

     27,600       2,922       (4,015 )     (84,097 )
                                

Balance, end of period

   $ 8,434     $ 11,826     $ 8,434     $ 11,826  
                                

Components of Accumulated Other Comprehensive Income

        

Commodity related derivative hedges

       $ 15,460     $ 31,476  

Interest rate derivative hedges

         277       4,765  

Available-for-sale securities

         1,503       1,058  

Minority interests

         (8,806 )     (25,473 )
                    

Balance, end of period

       $ 8,434     $ 11,826  
                    

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

 

4


Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (DEFICIT)

For the Six Months Ended February 28, 2007

(Dollars in thousands)

(unaudited)

 

     General
Partner
    Common
Unitholders
    Class B
Unitholders
    Class C
Unitholders
 

Balance, August 31, 2006

   $ (69 )   $ (9,586 )   $ 53,130     $ —    

Unit issuances (Note 3)

     —         212,659       —         4,455  

Equity issue costs of Class C Units

     —         —         —         (203 )

Assumption of related company debt (Note 3)

     —         —         —         (70,500 )

Distribution to partners

     (452 )     (83,794 )     (1,645 )     (28,261 )

Purchase premium on ETP Class G Units (Note 15)

     —         (451,150 )     —         —    

Unit-based compensation

     —         9       —         —    

Net income

     612       119,949       2,230       55,605  

Conversion to Common Units

     —         (38,904 )     —         38,904  
                                

Balance, February 28, 2007

   $ 91     $ (250,817 )   $ 53,715     $ —    
                                

The accompanying notes are an integral part of this condensed consolidated financial statement.

 

5


Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

 

     Six Months Ended February 28,  
     2007     2006  

NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES

   $ 444,025     $ 332,360  
                

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Cash paid for acquisitions, net of cash acquired

     (83,085 )     (29,946 )

Working capital settlement on prior year acquisitions

     —         19,653  

Capital expenditures

     (542,930 )     (255,101 )

Advances to and investment in affiliates (Note 3)

     (954,397 )     —    

Proceeds from the sale of assets

     19,200       3,875  
                

Net cash used in investing activities

     (1,561,212 )     (261,519 )
                

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from borrowings

     3,745,207       1,433,188  

Principal payments on debt

     (2,641,151 )     (1,811,322 )

Redemption of Common Units

     —         (131,620 )

Net proceeds from issuance of Common and Class C Units

     212,455       474,741  

Distributions to partners

     (114,152 )     (34,225 )

Debt issuance costs

     (21,303 )     (1,196 )
                

Net cash provided by (used in ) financing activities

     1,181,056       (70,434 )
                

INCREASE IN CASH AND CASH EQUIVALENTS

     63,869       407  

CASH AND CASH EQUIVALENTS, beginning of period

     26,204       33,459  
                

CASH AND CASH EQUIVALENTS, end of period

   $ 90,073     $ 33,866  
                

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

 

6


Table of Contents

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in thousands, except per unit data)

(unaudited)

 

1. OPERATIONS AND ORGANIZATION:

The accompanying unaudited condensed consolidated financial statements include the accounts of Energy Transfer Equity, L.P. (the “Partnership”, “ETE” or the “Parent Company”), ETE’s controlled subsidiary, Energy Transfer Partners, L.P., a publicly-traded master limited partnership (“ETP”), and ETE’s wholly-owned subsidiaries, Energy Transfer Partners GP, L.P., the general partner of ETP (“ETP GP”) and Energy Transfer Partners, L.L.C., the general partner of ETP GP (“ETP LLC”). The results of operations for ETP in turn include the results of operations for ETP’s wholly-owned subsidiaries: La Grange Acquisition, L.P. dba Energy Transfer Company (“ETC OLP”), Energy Transfer Interstate Holdings, LLC (“ET Interstate”) the parent company of Transwestern Pipeline Company, LLC (“Transwestern”), Heritage Operating L.P. (“HOLP”), Titan Energy Partners, LP (“Titan”) (collectively the “Operating Partnerships”) and Heritage Holdings, Inc. (“HHI”). The accompanying financial statements are presented for the three and six months ended February 28, 2007 and 2006. The comparability of these financial statements is affected by ETP’s Titan acquisition included in the results of operations beginning June 1, 2006 (see Note 3), ETP’s purchase of 50% of CCE Holdings, LLC (“CCEH”) on November 1, 2006 for the month ended November 30, 2006, ETP’s purchase of Transwestern in December 2006 (see Note 3), the Parent Company’s purchase of the minority interest ownership of ETP GP (see Note 3) and the Parent Company’s purchase of additional limited partner interests in ETP (see Note 13).

The Partnership was formed as a Texas limited partnership in September 2002 and converted to a Delaware limited partnership in August 2005. ETE’s Common Units are publicly traded on the New York Stock Exchange (“NYSE”) under the ticker symbol “ETE”. ETE completed its IPO of 24,150,000 Common Units in February 2006. ETE’s partnership agreement contains provisions which govern the relative ownership interests in the Partnership.

LE GP, LLC (“LE GP”), the general partner of ETE, is a Delaware limited liability company. LE GP is ultimately owned and controlled by the Co-CEOs of ETP and Natural Gas Partners VI, L.P., a venture capital investor.

Under the terms of ETE’s partnership agreement, the limited partners’ potential liability is limited to their investment in the Partnership. The general partner of ETE manages and controls the business and affairs of the Partnership. The limited partners of ETE are not involved in the management and control of ETE.

The accompanying condensed consolidated balance sheet as of August 31, 2006, which has been derived from audited financial statements, and the unaudited interim financial statements and notes thereto of Energy Transfer Equity, L.P., and subsidiaries as of February 28, 2007 and for the three and six month periods ended February 28, 2007 and 2006, 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 Securities and Exchange Commission. 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 operations and 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.

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 and subsidiaries as of February 28, 2007, and the results of their operations for the three and six-month periods ended February 28, 2007 and 2006, and their cash flows for the six months ended February 28, 2007 and 2006. The unaudited interim condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of ETE and subsidiaries for the fiscal year ended August 31, 2006 presented in the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2006, as filed with the Securities and Exchange Commission on November 29, 2006.

 

7


Table of Contents

Certain prior period amounts have been reclassified to conform to the 2007 presentation. These reclassifications have no impact on net income or total partners’ capital.

Business Operations

In order to simplify the obligations of the Partnership under the laws of several jurisdictions in which we conduct business, our activities are conducted through four subsidiary operating partnerships, ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations, Transwestern Pipeline, a Delaware limited liability company engaged in interstate transportation of natural gas, HOLP, a Delaware limited partnership engaged in retail and wholesale propane operations, and Titan, a Delaware limited partnership engaged in retail propane operations. The Partnership, the Operating Partnerships, and their subsidiaries are collectively referred to in this report as “we”, “us”, “ETE”, “Parent Company”, or the “Partnership.”

The Parent Company has no separate operating activities apart from those conducted by the Operating Partnerships. The Parent Company’s principal sources of cash flow are its direct and indirect investments in the limited and General Partner interests in ETP.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its general and limited partners. The Parent Company-only assets and liabilities of ETE are not available to satisfy the debts and other obligations of ETP and its consolidated subsidiaries. In order to fully understand the financial condition of the Partnership on a stand-alone basis, see Note 20 for stand-alone financial information apart from that of the consolidated partnership information included herein.

 

2. ESTIMATES AND SIGNIFICANT ACCOUNTING POLICIES:

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 disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and transportation and storage segments are estimated using volume estimates and market prices. Any difference between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the three and six months ended February 28, 2007 and 2006 represent the actual results in all material respects.

Some of the other more 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, deferred taxes, assets and liabilities resulting from the regulated ratemaking process (as discussed below), environmental reserves, and general business and medical self-insurance reserves. Actual results could differ from those estimates.

Significant Accounting Policies

As a result of the acquisition of Transwestern on December 1, 2006, we have the following significant accounting policies in addition to the significant accounting policies described in our Form 10-K for the year ended August 31, 2006:

Revenue Recognition - Transwestern is subject to Federal Energy Regulatory Commission (FERC) regulations. As a result, FERC may require the refund of revenues collected during the pendency of a rate proceeding in a final order. Transwestern establishes reserves for these potential refunds, as appropriate. No such reserves were required at February 28, 2007.

Property, Plant and Equipment - An accrual of allowance for funds used during construction (AFUDC) is a utility accounting practice calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of servicing the capital invested in construction work-in-progress. AFUDC has been segregated into two component parts – borrowed funds and equity funds. The allowance for borrowed and equity funds used during construction totaled $722 for the three and six months ended February 28, 2007.

 

8


Table of Contents

System Gas - Transwestern accounts for system balancing gas using the fixed asset accounting model established under FERC Order No. 581. Under this approach, system gas volumes are classified as fixed assets and valued at historical cost. Encroachments upon system gas are valued at current market prices. Transwestern may sell system gas in excess of its system operational requirements.

Depreciation and Amortization - The provision for depreciation and amortization is computed using the straight-line method based on estimated economic or FERC mandated lives. Transwestern’s composite depreciation rates are applied to the FERC functional groups of gross property having similar economic characteristics. Transmission Plant is depreciated at rates ranging from 1.2 percent to 2.86 percent per year. General Plant is depreciated at 10.0 percent per year. Intangible assets are amortized at rates ranging from 8.0 percent to 20.0 percent per year.

Employee Benefits - Transwestern has entered into a VEBA trust (the “VEBA Trust”) agreement with Bank One Trust Company as a trustee. The VEBA Trust has established or adopted plans to provide certain post-retirement life, sick, accident and other benefits. The VEBA Trust is a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to employees of Transwestern. Transwestern’s plan is in an overfunded position as of February 28, 2007. As the plans are supported through rates charged to customers, under FASB Statement No. 71, Accounting for Effects of Certain Types of Regulation (“SFAS 71”), to the extent Transwestern has collected amounts in excess of what is required to fund the plan, Transwestern has an obligation to refund the excess amounts to customers through rates. As such, Transwestern has recorded the overfunded position of $830 within deferred assets and a corresponding regulatory liability of $830.

Transwestern accounts for its other post employment benefits (OPEB) liability and expense on an actuarial basis, recording its health and life benefit costs over the active service period of employees to the date of full eligibility for the benefits.

Regulatory Assets and Liabilities - Transwestern is subject to regulation by certain state and federal authorities, is part of our interstate transportation segment and has accounting policies that conform to SFAS 71, which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the condensed consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

New Accounting Standards

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not

 

9


Table of Contents

recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. In February 2007 the SEC clarified that if a registrant changes how it classifies interest and penalties upon adoption of FIN 48, it should not reclassify amounts in prior periods. However, the registrant should disclose its prior classification policy. We are currently evaluating FIN 48 and have not yet determined the impact of such on our financial statements. We plan to adopt this statement on September 1, 2007.

FASB Staff Position No. EITF 00-19-2, Accounting for Registration Payment Arrangements (“FSP 00-19-2”). FSP 00-19-2, issued in December 2006, provides guidance related to the accounting for registration payment arrangements. FSP 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with FASB No. 5, Accounting for Contingencies (SFAS No. 5). FSP 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception, the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. FSP 00-19-2 applies immediately to any registration payment arrangement entered into subsequent to the issuance of the Staff Position. For such arrangements issued prior to the issuance of FSP-00-19-2, the guidance is effective for financial statements issued for fiscal years beginning after December 15, 2006 and interim periods within those fiscal years. We are currently evaluating FSP 00-19-2 and have not yet determined the impact of such on our financial statements. We plan to adopt this Staff Position beginning September 1, 2007.

SFAS No. 154, Accounting Changes and Error Correction – A Replacement of APB Opinion No. 20 and FASB Statement No. 3 (“SFAS 154”). In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Management adopted the provisions of SFAS 154 September 1, 2006, as required. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors that occur in the future.

SFAS No. 155, Accounting for Certain Hybrid Financial Instruments – An Amendment of FASB Statements No. 133 and 140 (“SFAS 155”). SFAS 155 is effective for all financial instruments acquired, issued, or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Early application is permitted only if: (a) it occurs at the beginning of an entity’s fiscal year and (b) the entity has not yet issued any interim or annual financial statements for that fiscal year. We intend to adopt this statement when required at the start of fiscal year beginning September 1, 2007. The adoption of this statement is not expected to have a significant impact on us.

SFAS No. 157, Fair Value Measurement, (“SFAS 157”). This new standard provides guidance for using fair value to measure assets and liabilities. The FASB believes the standard also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. In this standard, the FASB clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability.

 

10


Table of Contents

In support of this principle, SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning September 1, 2008.

SFAS Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of SFAS Statements No. 87, 88, 106 and 132(R), (“SFAS 158”). Issued in September 2006, this statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multi-employer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. We adopted the recognition and disclosure provisions of SFAS 158 on December 1, 2006 in connection with our acquisition of Transwestern, the effect of which was not material. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. Management does not believe the adoption of the measurement provisions of this statement will have a material impact on our financial statements.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115, (“SFAS 159”). This new standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective, however, the amendment applies to all entities with available-for-sale and trading securities. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings (or another performance indicator if the business entity does not report earnings) at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes the choice in the first 120 days of that fiscal year and also elects to apply the provisions of FASB Statement No. 157, Fair Value Measurements (discussed above). We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning September 1, 2008.

EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross Versus Net Presentation) (“EITF 06-3”). This accounting guidance requires companies to disclose their policy regarding the presentation of tax receipts on the face of their income statements. The scope of this guidance includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes (gross receipts taxes are excluded). This guidance is effective for interim and annual reporting periods beginning after December 15, 2006 with earlier application permitted. As a matter of policy, we report such taxes on a net basis. We will adopt this EITF during our 2007 fiscal quarter ending May 31, 2007.

SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). In September 2006, the Securities and Exchange Commission (SEC) provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB 108 is effective for fiscal years ending after November 15, 2006. We are presently reviewing the impact of the adoption of SAB 108. However, we do not expect such adoption to have a material impact on our consolidated financial statements. We expect to adopt SAB 108 by August 31, 2007.

 

11


Table of Contents
3. SIGNIFICANT ACQUISITIONS:

Fiscal year 2007 acquisitions

On November 1, 2006, the Parent Company acquired from Energy Transfer Investments, L.P. (“ETI”, a partnership also controlled by LE GP) the remaining 50% of the Class B Limited Partner interests in ETP GP owned by ETI. The Parent Company recorded this acquisition at ETI’s historical cost of $4,456 as required under GAAP due to the fact that the Parent Company and ETI are companies under common control. As a result, the Parent Company now owns 100% of the Incentive Distribution Rights of ETP. The acquisition was effected through the issuance of 83,148,900 newly created Parent Company Class C Units and the assumption by the Parent Company of approximately $70,500 of ETI’s indebtedness. The assumption of this debt represents a non-cash financing activity. The Class C Units were recorded at the net value of the debt assumption (accounted for as a distribution to ETI) and the value of the ETP GP Class B Units acquired, a net amount of ($66,044). The Class C Units have essentially the same voting rights and rights to distributions as the Common Units and Class B Units. The Class C Units converted into Common Units upon approval by the ETE Common Unitholders on February 22, 2007.

Also on November 1, 2006, the Parent Company acquired additional limited partner interests in ETP (Class G Units, see Note 15) which increased the Parent Company’s aggregate ownership in ETP’s limited partner interests to approximately 46%.

In September 2006, ETP acquired two small gathering systems in east and north Texas for an aggregate purchase price of approximately $30,589 in cash. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $25,000 to be determined eighteen months from the closing date. We will record the required adjustment to the purchase price allocation when the amount of actual contingent consideration is determinable beyond a reasonable doubt. These systems provide us with additional capacity in the Barnett Shale and in the Travis Peak area of east Texas and are included in our midstream operating segment. The cash paid for acquisitions was financed primarily from advances under the ETP Revolving Credit Facility.

On November 1, 2006, pursuant to agreements entered into with GE Energy Financial Services (“GE”) and Southern Union Company (“Southern Union”), ETP acquired the member interests in CCEH from GE and certain other investors for $1,000,000. ETP financed a portion of the CCEH purchase price with the proceeds from its issuance of 26,086,957 Class G Units to the Parent Company simultaneous with the closing on November 1, 2006. The member interests acquired represented a 50% ownership in CCEH. On December 1, 2006, in a second and related transaction, CCEH redeemed ETP’s 50% interest ownership in CCEH in exchange for 100% ownership of Transwestern which owns the Transwestern Pipeline, a 2,400 mile interstate natural gas pipeline. Following the final step, Transwestern became a new operating subsidiary and separate segment of ETP.

The total acquisition cost for Transwestern, net of cash acquired, was as follows:

 

Basis of investment in CCEH at November 30, 2006

   $ 956,348  

Distributions received on December 1, 2006

     (6,217 )

Fair value of short and long-term debt assumed

     532,377  

Other assumed long-term indebtedness

     10,097  

Current liabilities assumed

     40,194  

Cash acquired

     (7,777 )

Acquisition costs incurred

     11,753  
        

Total

   $ 1,536,775  
        

During the six months ended February 28, 2007, HOLP and Titan collectively acquired substantially all of the assets of three propane businesses. The aggregate purchase price for these acquisitions totaled $10,608 which included $10,266 of cash paid, net of cash acquired, and liabilities assumed of $342. The cash paid for acquisitions was financed primarily with advances from ETP’s and HOLP’s Senior Revolving Credit Facilities.

In December 2006 we purchased a gathering system in north Texas for $32,000. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $21,000 to be determined two years after the closing date. We will record the required adjustment to the purchase price allocation when the amount of the actual contingent consideration is determinable beyond a reasonable doubt. The gathering system consists of approximately 36 miles of pipeline and has an estimated capacity of 70 MMcf/d. We expect the gathering system will allow us to continue expanding in the Barnett Shale area of north Texas.

 

12


Table of Contents

In January 2007 we purchased a gathering system in New Mexico for $8,000. The gathering system, which is included in our midstream segment, is approximately 27 miles long and is our first gathering system in New Mexico.

Except for the acquisition of the interests in ETP GP, the purchase of Class G Units from ETP and the 50% member interests in CCEH, the acquisitions discussed above were accounted for under the purchase method of accounting in accordance with SFAS No. 141 and the purchase prices were allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition. The acquisition of the 50% member interest in CCEH was accounted for under the equity method of accounting in accordance with APB Opinion No. 18, through November 30, 2006. The acquisition of 100% of Transwestern has been accounted for under the purchase method of accounting since the acquisition on December 1, 2006. The acquisition of the interests in ETP GP was accounted for on the basis of historical costs, as discussed above. The purchase of Class G Units from ETP was accounted for as described in Note 15. Pro forma effects of the Transwestern acquisition and the purchase of additional interest in ETP are discussed below. In the aggregate, the other acquisitions described above are not material for pro forma disclosure purposes.

The following table presents the purchase accounting allocation of the acquisition cost to the assets acquired and liabilities assumed based on their fair values for the acquisitions described above occurring during the period ended February 28, 2007, net of cash acquired:

 

     Midstream and
Intrastate
Transportation and
Storage Acquisitions
(Aggregated)
   Transwestern
Acquisition
    Propane
Acquisitions
(Aggregated)
 

Accounts receivable

   $ —      $ 20,101     $ 108  

Inventory

     —        —         43  

Prepaid and other current assets

     47,656      12,602       25  

Property, plant, and equipment

     23,015      1,254,968       9,222  

Intangibles and other assets

     —        133,880       475  

Goodwill

     —        115,224       735  
                       

Total assets acquired

     70,671      1,536,775       10,608  
                       

Accounts payable

     —        (7,432 )     —    

Customer advances and deposits

     —        —         (26 )

Accrued and other current liabilities

     —        (32,762 )     —    

Short-term debt (paid in December 2006)

     —        (13,000 )     —    

Long-term debt

     —        (519,377 )     (316 )

Other long-term obligations

     —        (10,097 )     —    
                       

Total liabilities assumed

     —        (582,668 )     (342 )
                       

Net assets acquired

   $ 70,671    $ 954,107     $ 10,266  
                       

The purchase price for the acquisitions has been initially allocated based on the estimated fair value of the assets acquired and liabilities assumed. The Transwestern allocation was based on the preliminary results of independent appraisals. The purchase price allocations have not been completed and are subject to change. We expect to complete the allocations during the first quarter of fiscal year 2008.

Included in the additions for interstate property, plant and equipment is an aggregate plant acquisition adjustment of $446,154, which represents costs allocated to Transwestern’s transmission plant. This amount has not been included in the determination of tariff rates Transwestern charges to its regulated customers. The unamortized balance of this adjustment was $442,967 at February 28, 2007 and is being amortized over 35 years, the composite weighted average estimated remaining life of Transwestern’s assets as of the acquisition date.

Regulatory assets, included in intangible and other long-term assets on the condensed consolidated balance sheet, established in the Transwestern purchase price allocation consist of the following:

 

Accumulated reserve adjustment

   $ 41,985

AFUDC gross-up

     9,570

Environmental costs

     6,623

South Georgia deferred tax receivable

     2,581

Other

     891
      

Total regulatory assets acquired

   $ 61,650
      

 

13


Table of Contents

At February 28, 2007, all of Transwestern’s regulatory assets are considered probable of recovery in rates.

We recorded the following intangible assets and goodwill in conjunction with the acquisitions described above:

 

     Midstream and
Intrastate
Transportation and
Storage Acquisitions
(Aggregated)
   Transwestern
Acquisition
   Propane
Acquisitions
(Aggregated)

Contract rights (6 to 15 years)

   $ 23,015    $ 47,582    $ —  

Financing costs (7 to 9 years)

     —        13,410      —  

Other

     —        —        475
                    

Total amortizable intangible assets

     23,015      60,992      475

Goodwill

     —        115,224      735
                    

Total intangible assets and goodwill acquired

   $ 23,015    $ 176,216    $ 1,210
                    

Goodwill was warranted because these acquisitions enhance our current operations and certain acquisitions are expected to reduce costs through synergies with existing operations. We expect all of the goodwill acquired to be tax deductible. We do not believe that the acquired intangible assets have any significant residual value at the end of their useful life.

On December 13, 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of the Midcontinent Express Pipeline (“MEP”). The approximately 500-mile pipeline, which will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco in Butler, Alabama, will have an initial capacity of 1.4 Bcf per day. Pending necessary regulatory approvals, the approximately $1,250,000 pipeline project is expected to be in service by February 2009. MEP has prearranged binding commitments from multiple shippers for 800,000 dekatherms per day which includes a binding commitment from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation, for 500,000 dekatherms per day. MEP has executed a firm capacity lease agreement for up to 500,000 dekatherms per day of capacity on the Oklahoma intrastate pipeline system of Enogex, a subsidiary of OGE Energy, to provide transportation capacity from various locations in Oklahoma into and through MEP. The new pipeline will also interconnect with Natural Gas Pipeline Company of America, a wholly-owned subsidiary of Kinder Morgan, Inc., and with our previously announced 36-inch pipeline extending from the Barnett Shale and interconnecting with our Texoma pipeline near Paris, Texas. The MEP joint venture will be accounted for using the equity method of accounting prescribed by APB Opinion No. 18.

Fiscal year 2006 acquisitions

On February 8, 2006, ETE purchased 1,069,850 Common Units and 2,570,150 Class F Units representing limited partnership interests in ETP. This purchase increased ETE’s ownership percentage in ETP limited partners interests from approximately 31% to approximately 33%. The Class F Units were converted to ETP Common Units on August 16, 2006.

On June 1, 2006, ETP acquired all the propane operations of Titan for cash of approximately $548,000, after working capital adjustments and net of cash acquired, and liabilities assumed of approximately $46,000. We accounted for the Titan acquisition as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141. The purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the acquisition based on the results of an independent appraisal. As of February 28, 2007, we are waiting on certain information required to reasonably estimate the fair value of one of the assets acquired in the Titan acquisition. We expect to complete

 

14


Table of Contents

the purchase allocation during our third quarter of fiscal year 2007. The Titan operations have been included since the date of acquisition, thus the condensed consolidated results of operations for the three and six months ended February 28, 2007 include the Titan results of operations for the entire period. However, the three and six months ended February 28, 2007 do not include any of the Titan results of operations.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the six months ended February 28, 2007 and the three and six months ended February 28, 2006 are presented as if the Transwestern acquisition and the purchase of additional interests in ETP had been made on September 1, 2005. The operations of Transwestern and the impact of our additional ownership interests in ETP have been included in our statements of operations since acquisition on December 1, 2006 and November 1, 2006, respectively. Thus, pro forma information for the three months ended February 28, 2007 is not required.

 

     Six Months Ended
February 28, 2007
   Three Months Ended
February 28, 2006
   Six Months Ended
February 28, 2006

Revenues

   $ 3,509,817    $ 2,504,242    $ 4,981,784

Net income

   $ 182,372    $ 53,228    $ 97,647

Limited Partners’ interest in net income

   $ 181,747    $ 52,915    $ 97,050

Basic earnings per Limited Partner Unit

   $ 0.85    $ 0.24    $ 0.46

Diluted earnings per Limited Partner Unit

   $ 0.85    $ 0.24    $ 0.46

The pro forma consolidated results of operations include adjustments to give effect to depreciation of the amounts allocated to depreciable and amortizable assets, interest expense on acquisition debt, and certain other adjustments. 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.

 

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 which are subject to an insignificant risk of change in value.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, such balances may be in excess of the Federal Deposit Insurance Corporation (“FDIC”) insurance limit.

Net cash flows provided by operating activities is comprised as follows:

 

     Six Months Ended February 28,  
     2007     2006  

Net income

   $ 178,396     $ 64,036  

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

    

Depreciation and amortization

     85,279       62,037  

Amortization of finance costs charged to interest expense

     3,285       2,278  

Other non-cash

     (6,101 )     (2,204 )

Non-cash compensation on unit grants

     6,080       58,780  

Undistributed minority interests

     10,603       144,746  

Changes in operating assets and liabilities:

    

Accounts receivable

     (23,461 )     23,170  

Accounts receivable from related companies

     (234 )     1,799  

Inventories

     193,388       64,218  

Deposits paid to vendors

     54,837       4,250  

Exchanges receivable

     (8,700 )     16,731  

Prepaid expenses and other

     16,067       (5,724 )

Intangibles and other long-term assets

     (952 )     112  

Regulatory assets

     (5,055 )     —    

Accounts payable

     (45,818 )     (141,928 )

Accounts payable to related companies

     1,499       (393 )

Customer advances and deposits

     (62,462 )     (113,592 )

Exchanges payable

     7,274       (6,241 )

Accrued and other current liabilities

     (1,198 )     7,591  

Other

     8,393       (4,933 )

Income taxes payable

     (88 )     21,527  

Price risk management liabilities, net

     32,993       136,100  
                

Net cash provided by operating activities

   $ 444,025     $ 332,360  
                

 

15


Table of Contents

Supplemental cash flow information is as follows:

 

     Six Months Ended February 28,
     2007    2006

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

     

Cash paid during the period for interest, net of $10,543 and $2,321 capitalized for February 28, 2007 and 2006, respectively

   $ 112,558    $ 17,340
             

Cash paid during the period for income taxes

   $ 5,946    $ 3,007
             

Transfer of investment in affiliate in purchase of Transwestern (Note 3)

   $ 956,348    $ —  
             

 

5. ACCOUNTS RECEIVABLE:

Our intrastate midstream and transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other forms of security (corporate guaranty, prepayment, or master set off agreement). Management reviews midstream and transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and transportation and storage operations. Management believes that the occurrence of bad debts in our intrastate midstream and transportation and storage segments was not significant for the three or six months ended February 28, 2007; therefore, an allowance for doubtful accounts for the midstream and transportation and storage segments was not deemed necessary. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense recognized for the three or six months ended February 28, 2007 and 2006 in the midstream and intrastate transportation and storage segments.

Transwestern has a concentration of customers in the electric and gas utility industries. This concentration of customers may impact Transwestern’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral to Transwestern. Transwestern sought additional assurances from customers due to credit concerns, and held aggregate prepayments of $598 at February 28, 2007, which are recorded in customer advance and deposits in the condensed consolidated balance sheets. Transwestern’s management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Transwestern establishes an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables. Transwestern considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectibility. There was no bad debt expense recognized for the three months ended February 28, 2007 related to Transwestern.

HOLP and Titan grant credit to their customers for the purchase of propane and propane-related products. Included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane and Titan’s

 

16


Table of Contents

retail propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane operations are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane segments is based on management’s assessment of the realizability of customer accounts, based on the overall creditworthiness of our customers, and any specific disputes.

We enter into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the condensed consolidated balance sheets.

Accounts receivable consisted of the following:

 

     February 28,
2007
    August 31,
2006
 

Accounts receivable - midstream and transportation and storage

   $ 532,059     $ 570,569  

Accounts receivable - propane

     190,027       108,976  

Less – allowance for doubtful accounts

     (4,129 )     (4,000 )
                

Total, net

   $ 717,957     $ 675,545  
                

The activity in the allowance for doubtful accounts for the retail and wholesale propane segments consisted of the following for the six months ended February 28, 2007:

 

     February 28,
2007
 

Balance, beginning of period

   $ 4,000  

Provision for loss on accounts receivable

     851  

Accounts receivable written off, net of recoveries

     (722 )
        

Balance, end of period

   $ 4,129  
        

 

6. INVENTORIES:

Inventories consist principally of natural gas held in storage which is valued at the lower of cost or market utilizing the weighted average cost method. Propane inventories are also valued at the lower of cost or market utilizing the weighted-average cost of propane delivered to the customer service locations, including storage fees and inbound freight costs. The cost of appliances, parts and fittings is determined by the first-in, first-out method.

Inventories consisted of the following:

 

     February 28,
2007
   August 31,
2006

Natural gas, propane and other NGLs

   $ 178,024    $ 371,430

Appliances, parts and fittings and other

     16,666      15,710
             

Total inventories

   $ 194,690    $ 387,140
             

 

7. PROPERTY, PLANT AND EQUIPMENT:

Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated economic or FERC mandated lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations.

We review long-lived assets for impairment at least annually and 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 long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. No impairment of long-lived assets was required during the periods presented.

 

17


Table of Contents

Components and useful lives of property, plant and equipment were as follows:

 

     February 28,
2007
    August 31,
2006
 

Land and improvements

   $ 67,613     $ 63,383  

Buildings and improvements (10 to 30 years)

     109,163       70,976  

Pipelines and equipment (10 to 65 years)

     3,237,459       2,212,805  

Natural gas storage (40 years)

     91,282       91,177  

Bulk storage, equipment and facilities (3 to 30 years)

     455,272       108,834  

Tanks and other equipment (5 to 30 years)

     504,726       472,944  

Vehicles (5 to 10 years)

     136,991       120,710  

Right-of-way (20 to 65 years)

     188,007       112,185  

Furniture and fixtures (3 to 10 years)

     19,414       16,283  

Linepack

     38,994       24,821  

Pad Gas

     55,482       57,327  

Other (5 to 10 years)

     85,282       27,395  
                
     4,989,685       3,378,840  

Less – Accumulated depreciation

     (354,791 )     (274,809 )
                
     4,634,894       3,104,031  

Plus – Construction work-in-process

     891,456       644,583  
                

Property, plant and equipment, net

   $ 5,526,350     $ 3,748,614  
                

Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the current borrowing rate of ETP’s revolving credit facility. A total of $10,543 of interest was capitalized for pipeline construction projects during the six months ended February 28, 2007 (excluding AFUDC, see Note 2).

Depreciation expense for the periods is as follows:

 

Three Months Ended
February 28,
   Six Months Ended
February 28,
2007    2006    2007    2006
    $44,333            $29,696            $78,254            $57,315    
                

 

8. GOODWILL:

Goodwill is associated with acquisitions made for our midstream, intrastate transportation and storage, interstate transportation, and retail propane segments. Goodwill is tested for impairment annually at August 31, in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”). The changes in the carrying amount of goodwill for the six month period ended February 28, 2007 were as follows:

 

     Midstream    Intrastate
Transportation
and Storage
   Interstate
Transportation
   Retail
Propane
    Other    Total  

Balance, beginning of period

   $ 13,409    $ 10,327    $ —      $ 580,673     $ 29,589    $ 633,998  

Purchase accounting adjustments

     —        —        —        3,777       —        3,777  

Goodwill acquired

     —        —        115,224      735       —        115,959  

Sale of operations

     —        —        —        (1,742 )     —        (1,742 )
                                            

Balance, end of period

   $ 13,409    $ 10,327    $ 115,224    $ 583,443     $ 29,589    $ 751,992  
                                            

The purchase price allocations for the Transwestern and other fiscal 2007 acquisitions (see Note 3) and our Titan acquisition in fiscal 2006 are preliminary. The final assessment of value and allocations for the fiscal 2007 acquisitions are expected to be completed by the first quarter of fiscal year 2008. We expect to complete the Titan purchase price allocation in our third quarter of fiscal 2007. There is no guarantee that the amounts allocated to goodwill will not change.

 

18


Table of Contents
9. INTANGIBLES AND OTHER ASSETS:

Intangibles and other long-term assets are stated at cost net of amortization computed on the straight-line method. We eliminate from our balance sheet the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangibles and other long-term assets were as follows:

 

     February 28, 2007     August 31, 2006  
     Gross
Carrying
Amount
   Accumulated
Amortization
    Gross
Carrying
Amount
   Accumulated
Amortization
 

Amortizable intangible assets:

          

Noncompete agreements (5 to 15 years)

   $ 31,609    $ (15,255 )   $ 31,593    $ (13,012 )

Customer lists (3 to 15 years)

     129,161      (16,206 )     87,480      (11,640 )

Contract rights (6 to 15 years)

     23,015      (226 )     —        —    

Financing costs (3 to 15 years)

     55,777      (7,780 )     23,751      (4,721 )

Consulting agreements (2 to 7 years)

     —        —         132      (122 )

Other (10 years)

     2,677      (745 )     2,677      (422 )
                              

Total amortizable intangible assets

     242,239      (40,212 )     145,633      (29,917 )

Non-amortizable - Trademarks

     64,642      —         64,842      —    
                              

Total intangible assets

     306,881      (40,212 )     210,475      (29,917 )

Other long-term assets:

          

Regulatory assets

     61,650      —         —        —    

Investment in affiliates

     12,651      —         41,344      —    

Long-term price risk management assets

     1,766      —         2,192      —    

Other

     31,131      —         14,700      —    
                              

Total intangibles and other assets

   $ 414,079    $ (40,212 )   $ 268,711    $ (29,917 )
                              

Prior to February 28, 2007, the Partnership owned a 50% ownership interest in Mid-Texas Pipeline Company (“Mid-Texas”), a Texas general partnership, which owns approximately 139 miles of transportation pipeline that connects various receipt points in south Texas to delivery points at the Katy hub. Effective February 28, 2007 Mid-Texas was dissolved and each partner was assigned its 50% undivided interest in the pipeline. As a result of the dissolution and now owning an undivided interest, we control the marketing and bear the risk of ownership. As a result, we ceased the use of equity accounting at February 28, 2007 and will apply proportionate consolidation prospectively for our interest in the Mid-Texas pipeline. This represents a non-cash transaction.

Aggregate amortization expense of intangible assets is as follows:

 

     Three Months Ended
February 28,
   Six Months Ended
February 28,
     2007    2006    2007    2006

Reported in depreciation and amortization

   $ 4,082    $ 2,374    $ 7,025    $ 4,722
                           

Reported in interest expense

   $ 2,068    $ 1,077    $ 3,285    $ 2,278
                           

The estimated aggregate amortization expense for the next five fiscal years is $17,884 for the remainder of fiscal 2007; $27,239 for 2008; $26,173 for 2009; $24,177 for 2010, and $20,894 for 2011.

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 in accordance with Statement of Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”). 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 non-amortizable intangible assets for impairment annually at August 31, or more frequently if circumstances dictate, in accordance with SFAS 144. No impairment of intangible assets was required for the three and six month periods ended February 28, 2007 and 2006.

 

19


Table of Contents
10. ACCRUED AND OTHER CURRENT LIABILITIES:

Accrued and other current liabilities consist of the following:

 

     February 28,
2007
   August 31,
2006

Capital expenditures

   $ 53,068    $ 38,002

Employee wages and benefits

     43,549      40,236

Operating expenses

     12,013      16,839

Interest payable

     39,038      18,065

Other accrued expenses

     98,549      93,035
             

Total accrued and other current liabilities

   $ 246,217    $ 206,177
             

 

11. INCOME TAXES:

As a limited partnership, we are generally not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the three and six month periods ended February 28, 2007 and 2006, our non-qualifying income did not, or was not expected to, exceed the statutory limit.

Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS 109”). Under SFAS 109, deferred income taxes are recorded based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.

On May 18, 2006, the State of Texas enacted House Bill 3 which replaced the existing state franchise tax with a “margin tax”. In general, legal entities that conduct business in Texas are subject to the Texas margin tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period subsequent to the law’s effective date of January 1, 2007. For the three and six months ended February 28, 2007, we recognized current state income tax expense related to the Texas margin tax of $1,854. There was no comparable state tax expense for the periods ended February 28, 2006.

The components of our federal and state income tax provision (benefit) are summarized as follows:

 

     Three Months Ended
February 28,
    Six Months Ended
February 28,
 
     2007     2006     2007     2006  

Current provision:

        

Federal

   $ 3,336     $ 12,853     $ 6,487     $ 28,117  

State

     2,487       950       2,826       1,288  

Deferred benefit:

        

Federal

     (2,972 )     (10,013 )     (3,627 )     (4,074 )

State

     (275 )     (501 )     (239 )     (355 )
                                

Total Tax Provision

   $ 2,576     $ 3,289     $ 5,447     $ 24,976  
                                

The difference between the statutory rate and the effective rate is summarized as follows:

 

     Three Months Ended
February 28,
    Six Months Ended
February 28,
 
     2007     2006     2007     2006  

Federal statutory tax rate

   35.0 %   35.0 %   35.0 %   35.0 %

State income tax rate net of federal benefit

   0.7 %   3.3 %   0.7 %   3.3 %

Earnings not subject to tax at the Partnership level

   (34.7 )%   (36.5 )%   (34.0 )%   (30.3 )%
                        

Effective tax rate

   1.0 %   1.8 %   1.7 %   8.0 %
                        

 

20


Table of Contents
12. INCOME PER LIMITED PARTNER UNIT:

Basic net income per Limited Partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of Limited Partner interests outstanding. Diluted net income per Limited Partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of Limited Partner interests outstanding and the number of unvested ETE Incentive Units granted. For the diluted earnings per share computation, income allocable to the Limited Partners is reduced, where applicable, for the decrease in earnings from ETE’s Limited Partner unit ownership in ETP that would have resulted assuming the incremental units related to ETP’s unit-based compensation plans had been issued during the respective periods. Such units have been determined based on the treasury stock method.

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

 

     Three Months Ended
February 28,
    Six Months Ended
February 28,
 
     2007     2006     2007     2006  

Basic Net Income per Limited Partner Unit:

        

Limited partners’ interest in net income

   $ 146,889     $ 24,291     $ 177,784     $ 63,644  
                                

Weighted average limited partner units

     217,821,530       131,468,542       186,054,317       118,826,222  
                                

Basic net income per limited partner unit

   $ 0.67     $ 0.18     $ 0.96     $ 0.54  
                                

Diluted Net Income per Limited Partner Unit:

        

Limited partners’ interest in net income

   $ 146,889     $ 24,291     $ 177,784     $ 63,644  

Dilutive effect of subsidiary unit grants

     (267 )     (108 )     (270 )     (625 )
                                

Limited partners’ interest in net income

   $ 146,622     $ 24,183     $ 177,514     $ 63,019  
                                

Diluted average limited partner units

     217,821,530       131,468,542       186,054,317       118,826,222  
                                

Diluted net income per limited partner unit

   $ 0.67     $ 0.18     $ 0.95     $ 0.53  
                                

 

13. MINORITY INTERESTS:

The following table summarizes the changes in minority interest liability:

 

     February 28,
2007
 

Balance, August 31, 2006

   $ 1,439,127  

Minority interest in net income of subsidiaries

     143,726  

Distributions and other

     (134,143 )

Compensation under employee unit awards by subsidiary

     6,071  

Premium on ETE’s purchase of ETP units (see Note 15)

     451,150  

Change in accumulated other comprehensive income allocable to minority interests

     4,015  

Purchase of interest in consolidated subsidiary from ETI (see Note 3)

     (4,456 )
        

Balance, February 28, 2007

   $ 1,905,490  
        

 

21


Table of Contents
14. DEBT OBLIGATIONS:

Long-term debt we assumed in connection with the Transwestern acquisition on December 1, 2006 was as follows:

 

5.39% Notes due November 17, 2014

   $ 270,000  

5.54% Notes due November 17, 2016

     250,000  
        

Total long-term debt outstanding

     520,000  

Unamortized debt discount

     (628 )
        

Total long-term debt assumed

   $ 519,372  
        

No principal payments are required under any of the debt agreements prior to their respective maturity dates. However, in connection with our acquisition of Transwestern, due to a change in control provision in Transwestern’s debt agreements, Transwestern was required to pre-pay approximately $307,000 of long-term debt, of which $292,000 was paid in February 2007 and $15,000 was paid in March 2007. These payments were financed with borrowings under ETP’s Revolving Credit Facility.

Transwestern’s credit agreements contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and require certain debt to capitalization ratios.

ETP Senior Notes

On October 23, 2006, ETP issued a total of $800,000 aggregate principal amount of Senior Notes comprised of $400,000 of 6.125% Senior Notes due 2017 (the “2017 Notes”) and $400,000 of 6.625% Senior Notes due 2036 (the “2036 Notes” and together with the 2017 Notes, the “Notes”). ETP used the net proceeds of approximately $791,000 (net of bond discounts of $2,612 and financing costs of $6,050) from the issuance of the Notes to repay borrowings and accrued interest outstanding under the ETP Revolving Credit Facility, to pay expenses associated with the offering and for general partnership purposes. Interest on the notes will be due semiannually. ETP may redeem some or all of the Notes at any time, or from time to time, pursuant to the terms of the indenture. All of ETP’s obligations under the Notes are fully and unconditionally guaranteed by ETC OLP and Titan and substantially all of their present and future wholly-owned subsidiaries. These notes have been registered under the Securities Act pursuant to ETP’s S-3 Registration Statement which provides for the sale of a combination of units and debt totaling $1,500,000.

Revolving Credit Facilities and Term Loans

On November 1, 2006, the Parent Company entered into a First Amendment to Amended and Restated Credit Agreement, dated November 1, 2006 (as amended, the “Parent Company Credit Agreement”), which provided for an additional six year $1,300,000 Senior Secured Term Loan Series B Facility due February 8, 2012, with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National Association as Administrative Agent. The Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance debt assumed in the ETI transaction and for liquidity and general partnership purposes.

The Parent Company Credit Agreement also includes a $500,000 Senior Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011. The Parent Company Revolving Credit Facility also offers a Swingline loan option with a maximum borrowing of $10,000 and a daily rate based on LIBOR. The Parent Company Credit Agreement also has a $150,000 Senior Secured Term Loan Facility due February 8, 2012.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of February 28, 2007 was $1,726,500 with no amounts outstanding under the Swingline loan option. The total amount available under the Parent Company’s debt facilities as of February 28, 2007 was $233,500. The Parent Company Revolving Credit Facility also contains an accordion feature which will allow the Parent Company, subject to bank syndication’s approval, to expand the facility’s capacity up to an additional $100,000.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is 0.5%. Loans under the Parent Company Revolving Credit Facility, the $150,000 Senior Secured Term Loan

 

22


Table of Contents

Facility, and the $1,300,000 Senior Secured Term Loan Series B Facility bear interest at the Parent Company’s option at either (a) a base rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio. The weighted average interest rate was 7.15% for the amount outstanding on the Parent Company Senior Secured Revolving Credit Facility, and 7.10% for the amounts outstanding on the Parent Company $150,000 Senior Secured Term Loan Facility and the $1,300,000 Senior Secured Term Loan Series B Facility as of February 28, 2007.

The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries, including its ownership of 36.4 million ETP Common Units, 26.1 million ETP Class G Units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s 2% General Partner interest in ETP and 100% of ETP GP’s outstanding incentive distribution rights in ETP, which the Parent Company holds through its ownership of ETP GP.

ETP has a $1,500,000 Amended and Restated Revolving Credit Facility (the “ETP Revolving Credit Facility”) available through June 29, 2011. Amounts borrowed under the ETP Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. There is also a Swingline loan option with a maximum borrowing of $75,000 at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on our credit rating with a maximum fee of 0.175%. As of February 28, 2007, there was a balance of $783,755 in revolving credit loans (including $63,455 in Swingline loans) and $57,306 in letters of credit. The weighted average interest rate on the total amount outstanding at February 28, 2007, was 5.979%. The total amount available under the ETP Revolving Credit Facility as of February 28, 2007, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $658,939. The ETP Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt.

A $75,000 Senior Revolving Facility (the “HOLP Facility”) is available to HOLP through June 30, 2011. The HOLP Facility has a swingline loan option with a maximum borrowing of $10,000 at a prime rate. Amounts borrowed under the HOLP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined in the HOLP Facility credit agreement, 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 accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the HOLP Facility. As of February 28, 2007, there was no balance outstanding on the revolving credit loans. A Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Facility. There were outstanding Letters of Credit of $1,002 at February 28, 2007. The sum of the loans made under the HOLP Facility plus the Letter of Credit Exposure and the aggregate amount of all swingline loans cannot exceed the $75,000 maximum amount of the HOLP Facility. The amount available at February 28, 2007 was $73,998.

We were in compliance with all of the covenants of our consolidated debt agreements at February 28, 2007 and August 31, 2006.

 

15. PARTNERS’ CAPITAL AND UNIT BASED COMPENSATION PLANS:

Limited Partner Units

Limited partner interests in the Partnership are represented by Common and Class B Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement, as amended. As of February 28, 2007, we had limited partner interests represented by 215,300,501 Common Units and 2,521,570 Class B Units issued and outstanding that are entitled to receive distributions in accordance with their terms, an aggregated 99.68% Limited Partner interest.

Common Units

The change in Common Units during the six month period ended February 28, 2007 is as follows:

 

Balance, beginning of period

   124,360,520

Issuance of restricted Common Units

   1,948

Issuance of Common Units

   7,789,133

Conversion of Class C to Common Units

   83,148,900
    

Balance, end of period

   215,300,501
    

 

23


Table of Contents

On November 28, 2006 the Parent Company sold 7,789,133 Common Units to a group of institutional investors in a private placement at a price of $27.41 per unit, resulting in net proceeds of approximately $213,500. We granted registration rights to the investors. The Parent Company used the proceeds to repay indebtedness under its credit facility.

Class B Units

There were no new Class B Units issued, nor changes effected, during the six month period ended February 28, 2007. On March 27, 2007 the Class B Units were converted to Common Units.

Class C Units

The Class C Units issued and outstanding during the six month period ended February 28, 2007 were as follows:

 

Balance, beginning of period

   —    

Issuance of Class C Units to Energy Transfer Investments, L.P.

   83,148,900  

Conversion of Class C to ETE Common Units

   (83,148,900 )
      

Balance, end of period

   —    
      

On November 1, 2006, the Parent Company acquired from Energy Transfer Investments, L.P. (“ETI”) the remaining 50% of the Class B Limited Partner interests in ETP GP with the issuance of 83,148,900 Class C Units, which the Parent Company recorded at ETI’s historical cost of $4,456 (see Note 3).

On February 22, 2007, at a special unitholders’ meeting, the Common Unitholders of ETE approved a proposal to convert ETE’s Class C Units into 83,148,900 ETE Common Units. Following such approval, the Class C Units were converted into Common Units.

Sale of Common Units by Subsidiary

On November 1, 2006, the Parent Company purchased 26,086,957 Class G Units representing limited partnership interests in ETP. The price per unit paid for each of the Common Units was equal to $46.00 per unit, based upon a market discount from the New York Stock Exchange closing price of the ETP’s Common Units on October 31, 2006 of $48.94. ETP used a portion of the proceeds to purchase interests in CCEH (see Note 3). The Parent Company has been granted registration rights in connection with the issuance of the ETP Class G Units. ETP will have a unitholder meeting on May 1, 2007 to seek approval for the conversion of the Class G Units to Common Units (see Note 21).

The Parent Company recorded the premium of $451,150 (the difference between the Parent Company’s share of the underlying book value in ETP before and after the purchase of the Class G Units) as a reduction of the Parent Company’s limited partners’ capital with a corresponding increase in minority interest. The Parent Company’s ownership percentage in ETP limited partner interests as a result of the Class G Unit purchase increased from approximately 33% to approximately 46%.

Issuances of Subsidiary Units

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and the underlying book value arising from issuance of units by ETP (excluding unit issuances to the Parent Company) as capital transactions rather than electing the income recognition as permitted by SEC Staff Accounting Bulletin No. 51. If ETP issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment in ETP 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 Units during the three and six month periods ended February 28, 2007 and 2006.

 

24


Table of Contents

Contributions to Subsidiary

The Parent Company indirectly owns the entire 2% general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP is required to make contributions to ETP each time ETP issues limited partner interests for cash or in connection with acquisitions in order to maintain its 2% general partner interest in ETP. These contributions are generally paid by offsetting the required contributions against the funds ETP GP receives from ETP distributions on the general partner and limited partner interests owned by ETP GP. ETP GP was required to contribute $24,489 and $0 for the six months ended February 28, 2007 and 2006, respectively. ETE advanced the funds to pay the $24,489 contribution and at February 28, 2006 there was $21,218 remaining as a receivable from affiliates in the Parent Company stand alone balance sheet.

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. Our only cash-generating assets currently consist of limited and general partner interests, including incentive distribution rights, in ETP from which we receive quarterly distributions. We currently have no independent operations outside of our interests in ETP.

On October 19, 2006, the Parent Company paid a cash distribution related to the fourth quarter of fiscal year 2006 of $0.3125 per Common Unit, or $1.25 annually, to Unitholders of record at the close of business on October 5, 2006.

On January 19, 2007, the Parent Company paid a cash distribution related to the first quarter of fiscal year 2007 of $0.34 per Common Unit or $1.36 annually, to Unitholders of record at the close of business on January 4, 2007.

The total amount of distributions the Parent Company declared on March 28, 2007 (all from Available Cash from Operating Surplus) relating to the three months ended February 28, 2007 was as follows. These distributions will be paid on April 16, 2007 to Unitholders of record on April 9, 2007.

 

Limited Partners -

  

Common Units

   $ 79,327

General Partner

     246
      

Total distributions declared

   $ 79,573
      

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.

The Parent Company’s cash flows currently consist of distributions from ETP related to the following partnership interests, including incentive distribution rights in ETP:

 

   

ETE’s ownership of the 2% general partner interest in ETP, which it holds through its ownership interests in ETP GP.

 

   

62,500,797 ETP Units (including Class G Units), representing approximately 46% of the total outstanding ETP Units, which ETE holds directly; and

 

   

Effective November 1, 2006, 100% of the incentive distribution rights in ETP, which ETE holds through its ownership interests in ETP GP and which entitle it to receive specified percentages of the cash distributed by ETP as ETP’s per unit distribution increases.

On October 16, 2006, ETP paid a quarterly distribution related to the fourth quarter of fiscal year 2006 of $0.75 per ETP Common Unit, or $3.00 per unit annually, to ETP Unitholders of record at the close of business on October 5, 2006. In addition to these quarterly distributions, ETP GP received quarterly distributions for its general partner interest in ETP and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit.

The Parent Company’s incentive distribution rights entitle it to receive incentive distributions to the extent that quarterly distributions to ETP’s Unitholders exceed $0.275 per unit ($1.10 per unit on an annualized basis). These

 

25


Table of Contents

incentive distributions entitle the Parent Company to increasing percentages of ETP’s cash distributions based upon exceeding incentive distribution thresholds specified in ETP’s Partnership Agreement, which incentive distribution rights entitle the Parent Company to receive 50% of ETP’s cash distributions in excess of $0.4125 per unit. At current distribution levels, the Parent Company is entitled to receive cash distributions at the highest incentive distribution level of 50% with respect to ETP’s distributions in excess of $0.4125 per unit.

On January 15, 2007, ETP paid a quarterly distribution related to the first quarter of fiscal year 2007 of $0.7688 per Limited Partner Unit, or $3.075 per Limited Partner Unit annually, to Unitholders of record at the close of business on January 4, 2007.

The total amount of distributions the Parent Company received from ETP relating to its ownership of limited partner interests, general partner interests and incentive distribution rights of ETP during the six-month period ended February 28, 2007 is as follows:

 

Limited Partner Interests

   $ 75,358

General Partner Interest

     5,849

Incentive Distribution Rights

     71,897
      

Total distributions received from ETP

   $ 153,104
      

On March 26, 2007, ETP declared a per unit cash distribution of $0.7875, or $3.15 per Limited Partner Unit annually (a $0.0188 increase per Limited Partner Unit) for the quarter ended February 28, 2007, which will be paid on April 13, 2007 to Unitholders of record at the close of business on April 6, 2007.

The total amount of ETP distributions declared (all from Available Cash from Operating Surplus) related to the six months ended February 28, 2007 was as follows:

 

Limited Partners -

  

Common Units

   $ 172,573

Class E Units

     6,242

Class G Units

     40,598

General Partner -

  

2% Ownership

     6,646

Incentive Distribution Rights

     106,225
      
   $ 332,284
      

Based on ETP’s current quarterly distribution of $0.7875 per unit and the number of its Common Units outstanding at February 28, 2007, the Parent Company would be entitled to receive a quarterly cash distribution of $106,939 (or $427,756 on an annualized basis), which consists of $3,374 from the indirect ownership of the 2% general partner interest in ETP, $54,345 from the indirect ownership of the incentive distribution rights in ETP, $28,676 from the Common Units of ETP and $20,544 from the Class G Units of ETP.

Unit Based Compensation Plans

We follow the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) Accounting for Stock-based Compensation (“SFAS 123R”) for the unit-based compensation plans of the Parent Company and ETP. Adoption of SFAS 123R during fiscal 2006 did not have a material effect on our net income. As provided in SFAS 123R, the Partnership values the unit awards based on the per unit grant-date market value reduced, where appropriate, by the present value of the distributions expected to be paid on the units during the requisite service period to which the award recipients are not entitled. The present value of expected service period distributions is computed based on the risk-free interest rate, the expected life of the unit grants and the expected unit distributions.

We recognized compensation expense of $2,916 and $5,380 for the three months ended February 28, 2007 and 2006, respectively, and $6,080 and $5,827 for the six months ended February 28, 2007 and 2006, respectively, related to ETP’s and the Parent company’s unit-based compensation plans, as described below.

 

26


Table of Contents

ETE Long-Term Incentive Plan

Concurrently with the IPO during the second quarter of fiscal year 2006, 2,521,570 Class B Units were issued to FEM Group, L.P. (“FEM Group”), which is controlled by John W. McReynolds. Each Class B Unit represents a limited partner interest in ETE, is convertible into a Common Unit and is otherwise comparable to a Common Unit. On March 27, 2007 the Class B Units were converted to Common Units.

In addition, the Board of Directors or the Compensation Committee of the board of directors of the Partnership’s general partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 3,000,000 units, excluding the Class B Units discussed above.

On December 22, 2006, the Compensation Committee voted to award each ETE Director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary (“Director Participant”), who is then in office and, automatically on each September 1st thereafter, an award of Units equal to $15 divided by the fair market value of ETE Common Units on such date (“Annual Director’s Grant”). Each award to a Director Participant will vest at the rate of one third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, all awards to a Director Participant shall become fully vested upon a change in control, as defined by the 2004 Unit Plan. On December 22, 2006 a total of 1,948 restricted units were granted to ETE Directors, which are the only units outstanding under the ETE Long-Term Incentive Plan as of February 28, 2007.

ETP Unit-Based Compensation Plans

Employee Grants. ETP’s Compensation Committee, at its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the ETP 2004 Unit Plan (the “2004 Unit Plan”). All outstanding awards shall fully vest into units upon any Change in Control, as defined by the 2004 Unit Plan, or upon such terms as the ETP Compensation Committee may require at the time the award is granted.

ETP employee grants awarded under the 2004 Unit Plan will vest over a three-year period based upon the achievement of certain performance criteria. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. Vesting occurs based upon the total return to the ETP Unitholders as compared to a group of Master Limited Partnership peer companies. One third of the awards will vest and convert to ETP Common Units annually based on achievement of the performance criteria. Management deems it probable that all units will vest; thus, compensation expense was recorded. The issuance of ETP Common Units pursuant to the 2004 Unit Plan is intended to serve as a means of incentive compensation, therefore, no consideration will be payable by the plan participants upon vesting and issuance of the ETP Common Units.

We assumed a weighted average risk-free interest rate of 4.42% for the three and six months ended February 28, 2007 in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each employee grant. For the employee awards outstanding as of the period ended February 28, 2007, the grant-date average per unit cash distributions were estimated to be $5.15. Upon vesting, ETP Common Units are issued.

The following table shows the activity of the employee grants during the six months ended February 28, 2007:

 

     Number of
Units
    Weighted
Average
Fair Value
Per Unit

Unvested awards as of August 31, 2006

   357,750     $ 24.96

Awards granted

   399,500       43.36

Awards vested

   (154,239 )     23.78

Awards forfeited

   (61,472 )     33.38
            

Unvested awards as of February 28, 2007

   541,539     $ 38.02
            

 

27


Table of Contents

The total expected compensation expense to be recognized related to the unvested employee awards as of February 28, 2007 is $5,960 for the remainder of fiscal year 2007, $4,885 for fiscal year 2008, and $1,671 for fiscal year 2009.

Director Grants. Each ETP Director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary (“Director Participant”), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 2,000 ETP Common Units (the “Initial Director’s Grant”). Each Director Participant who is in office on September 1st shall automatically receive an award of Units equal to $25 (as of October 2006, see below) divided by the fair market value of an ETP Common Unit on such date (“Annual Director’s Grant”). Each grant of an award to a Director Participant will vest at the rate of one third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a Change in Control, as defined by the 2004 Unit Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by the ETP Compensation Committee.

We assumed a weighted average risk-free interest rate of 3.80% for the three and six months ended February 28, 2007 in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each Director Grant. For the Director Awards granted during the three and six months ended February 28, 2007, the grant-date average per unit cash distributions were estimated to be $4.95.

The following table shows the activity of the Director Grants during the six months ended February 28, 2007:

 

     Number of
Units
    Weighted
Average
Fair Value
Per Unit

Unvested awards as of August 31, 2006

   15,951     $ 22.54

Awards vested

   (7,025 )     22.45

Awards granted

   3,240       41.47
            

Unvested awards as of February 28, 2007

   12,166     $ 27.63
            

The total expected compensation expense to be recognized related to the unvested Director Awards as of February 28, 2007 is expected to be $89 for the remainder of fiscal year 2007, $60 for fiscal year 2008, and $14 for fiscal year 2009.

On October 17, 2006, the ETP Compensation Committee recommended, following its receipt and review of an independent third-party compensation study, and the Board of Directors approved, an amendment to the 2004 Unit Plan to provide that Annual Director’s Grants shall be equal to $25 divided by the fair market value of ETP Common Units on that date. All other Annual Director’s Grants shall be measured at September 1 of each year.

Long-Term Incentive Grants. The Compensation Committee of ETP may, from time to time, grant awards under the Plan to any executive officer or any employee it may designate as a participant in accordance with general guidelines under the Plan. As of February 28, 2007, there have been no Long-Term Incentive Grants made under the Plan.

Related Party Awards

Through February 28, 2007, a partnership (FEM Group) controlled by our President has awarded to a new officer of ETP certain rights related to units of ETE previously issued by ETE to our President. These rights include the economic benefits of ownership of these units based on a 5-year vesting schedule whereby the employee will vest in the units at a rate of 20% per year. None of the costs related to such awards are paid by ETP or ETE. Based on GAAP covering related party transactions and unit-based compensation arrangements, ETP is recognizing non-cash compensation expense over the vesting period based on the grant date per unit market value of ETE units awarded the employee assuming no forfeitures. Awards granted for the six months ended February 28, 2007 result in a total non-cash compensation expense of approximately $8,800 to be recognized over the related vesting period.

 

28


Table of Contents

For the three and six month periods ended February 28, 2007, ETP recognized non-cash compensation expense of $354 as a result of these awards. As these units were outstanding prior to these awards, the awards do not represent an increase in the number of outstanding units of either ETP or ETE and are not dilutive to cash distributions per unit with respect to either ETP or ETE. ETP expects to recognize non-cash compensation expense as follows in future periods related to these awards:

 

Remainder of fiscal 2007

   $ 2,124

Fiscal 2008

     2,969

Fiscal 2009

     1,717

Fiscal 2010

     1,009

Fiscal 2011

     508

Fiscal 2012

     119

 

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

Regulatory Matters

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. On October 31, 2006, in Docket No. RP06-614 the FERC issued its Order Accepting and Suspending Tariff Sheets Subject to Refund and Establishing a Hearing and Technical Conference (Commission’s October 31, 2006 Order). In this Order the Commission accepted and suspended the revised tariff sheets for the maximum five-month statutory period to be effective April 1, 2007, subject to refund, and subject to the outcome of a hearing established by this order. Transwestern and the active parties in this proceeding engaged in settlement negotiations to resolve all issues set for hearing by the Commission’s October 31, 2006 Order. On March 9, 2007, Transwestern filed with the FERC its Stipulation and Agreement of Settlement (Stipulation and Agreement) which, if approved by the commission, will settle these matters. The Stipulation provides for (i) revised base tariff rates, (ii) the amortization of certain costs, including the Enron Cash Balance Plan, regulatory commission expense, post retirement benefits, the accumulated reserve adjustment regulatory asset, deferred income taxes, and certain non-PCB environmental costs, and (iii) a depreciation rate of 1.20 percent for all transmission plant facilities.

On August 1, 2002, the FERC issued an Order to Respond (August 1 Order) to Transwestern. The order required Transwestern, within 30 days of the date of the order, to provide written responses stating why the FERC should not find that: (i) Transwestern violated FERC’s accounting regulations by failing to maintain written cash management agreements with Enron; and (ii) the secured loan transactions entered into by Transwestern in November 2001 were imprudently incurred and why the costs arising from such transactions should be passed on to ratepayers. On September 2, 2002, Transwestern filed a response to the August 1 Order and subsequently entered into a procedural settlement with the FERC staff that resolved, as to Transwestern, the issues raised by the August 1 Order. The FERC approved this settlement on October 31, 2002; however, a group of Transwestern’s customers filed a request for clarification and/or rehearing of the FERC order approving the settlement. This customer group claimed that there is an inconsistency between the language of the settlement agreement and the language of the FERC order approving the settlement. This alleged inconsistency relates to Transwestern’s ability to pass through to its ratepayers the costs of any replacement or refinancing of the secured loan transactions entered into by Transwestern in November 2001. Transwestern filed a response to the customer group’s request for rehearing and/or clarification and this matter is currently awaiting FERC action. If approved, the March 9, 2007 Stipulation in Docket No. RP06-614 (discussed above) would provide for the termination of this proceeding.

The Phoenix Expansion project, as filed with FERC on September 15, 2006, includes the construction and operation of approximately 260 miles of 36-inch or larger diameter pipeline extending from Transwestern’s existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area and certain looping on Transwestern’s existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline. Total project costs are estimated to be approximately $710,000 with a projected in-service date in the third or fourth calendar quarter of 2008, subject to FERC approval. Transwestern has incurred expenditures of $31,487 through February 28, 2007 for the Phoenix Expansion project.

 

29


Table of Contents

Commitments

As a result of the Transwestern acquisition we have additional non-cancelable operating leases for property and equipment which require annual rental payments of approximately $3,400 through year 2009 and $300 through year 2020. Transwestern is currently negotiating an extension of the operating lease expiring in 2009.

Total rental expense under our operating leases was approximately $5,838 and $12,189 for the three and six months ended February 28, 2007, respectively, and has been included in operating expenses in the condensed consolidated statements of operations.

In the normal course of our business, the Operating Partnerships purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that such terms are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

On October 3, 2006, we entered into a long-term agreement with CenterPoint Energy Resources Corp (“CenterPoint”) to provide the natural gas utility with firm transportation and storage services on our HPL System located along the Texas gulf coast region. Under the terms of this agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas storage capacity in our Bammel Storage facility. Under the new agreement with CenterPoint, we will no longer need to utilize predominately all of the Bammel Storage facility’s working gas capacity for supplying CenterPoint’s winter needs. This may reduce our working capital requirements that were necessary to finance the working gas while in storage and may provide us an opportunity to offer storage to third parties. This agreement went into effect on April 1, 2007.

We assumed in our HPL acquisition a contract with a service provider which obligated us to obtain certain compression, measurement and other services through 2007 with monthly payments of approximately $1,700. We terminated the measurement portion of this contract in October 2006 for a payment of approximately $7,000. The remaining compression services total approximately $800 per month through October 2007.

Litigation and Contingencies

The Operating Partnerships may, from time to time, be involved in litigation and claims arising out of their respective 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 coverages 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 and our Operating Partnerships from material expenses related to product liability, personal injury or property damage in the future.

In re Natural Gas Royalties Qui Tam Litigation. MDL Docket No. 1293 (D. WY), Jack Grynberg, an individual, has filed actions against a number of companies, including Transwestern, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against Transwestern. Transwestern believes that its measurement practices conformed to the terms of its FERC Gas Tariffs, which were filed with and approved by the Commission. As a result, Transwestern believes that is has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of FERC, and the defense that Transwestern complied with the terms of its tariffs) and will continue to vigorously defend against them, including any appeal which may be taken from the dismissal of the Grynberg case. Transwestern does not believe the outcome of this case will have a material adverse effect on its financial position, results of operations or cash flows. A hearing is scheduled for April 24, 2007 regarding Transwestern’s Supplemental Brief for Attorneys’ fees which was filed on January 8, 2007.

Transwestern is managing one threatened trespass action related to right of way (ROW) on Tribal or allottee land. The threatened action concerns 5,100 feet of ROW on private allotments within the Laguna Pueblo that expired on December 28, 2002. Transwestern received a letter dated March 19, 2003 from the United States Department of the Interior, Bureau of Indian Affairs (BIA) on behalf of the two allottees asserting trespass. Transwestern’s legal exposure related to this matter is not currently determinable. Negotiations are ongoing on this matter.

 

30


Table of Contents

Another action involves an agreement with the BIA covering 44 miles of ROW on a total of 68 Navajo allotments. This ROW agreement expired on January 1, 2004. One allottee sent a letter dated January 16, 2004 to the BIA claiming Transwestern trespassed and that allotee’s claim of trespass has been settled and his consent has been acquired. Transwestern resolved this matter by filing a renewal application with the BIA during October 2002. However, discussions are ongoing with the BIA to approve the renewal application.

Effective December 16, 2004, Citicorp North America, Inc. (Citicorp) claimed, in its capacity as the Paying Agent and Co-Administrative Agent, that any recovery in the litigation captioned Enron Corp. et al. v. Citigroup, Inc. et al. (the Litigation), together with legal fees and expenses incurred by Citicorp in defending the Litigation, would be indemnity obligations (the Obligations) of Transwestern under its Credit Agreement dated November 13, 2001. Under the terms of the Purchase Agreement, CCE Holdings, LLC and certain of its subsidiaries are indemnified against the Obligations by Enron and certain of its subsidiaries. In January of 2005, Enron gave notice that it would assume the defense of and indemnify CCE Holdings, LLC, against any action by Citigroup to collect from Transwestern. Discovery is ongoing in the adversary proceeding and Transwestern has not been joined in the litigation. Accordingly, Transwestern does not believe that it has any material liability from Citicorp’s claims.

At the time of the HPL 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 engaged in ongoing 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”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have 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. 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.

Following the natural gas market disruptions and related natural gas price volatility occurring in the Houston Ship Channel market around the times of the hurricanes in the fall of 2005, federal regulatory agencies commenced inquiries into certain activities during this period. Subsequently, the FERC and the Commodity Futures Trading Commission initiated investigations into whether ETP engaged in manipulative or improper trading activities in the Houston Ship Channel market around the times of the hurricanes in the Fall of 2005 as well as into certain of ETPs transportation activities. In connection with these investigations, we have responded to discovery subpoenas, and have otherwise provided information to, these agencies concerning our physical sales of natural gas and financial derivatives transactions, along with certain natural gas transportation activities, during the fall of 2005 and other periods. It is our position that our trading and transportation activities during these periods complied in all material respects with applicable rules and regulations. We anticipate that we will engage in discussions with these agencies related to their views of possible violations of applicable laws and regulations, and potential penalties related thereto, and that these discussions will involve settlement negotiations to resolve these matters. Management believes that these agencies will require a payment in order to conclude these investigations in a negotiated settlement basis. Our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the final outcome of these 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 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 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.

 

31


Table of Contents

As of February 28, 2007 and August 31, 2006, an accrual of $30,275 and $32,148, respectively, was recorded as accrued and other current liabilities on our condensed consolidated balance sheets for our contingencies and current litigation matters, excluding accruals related to environmental matters.

Environmental

Our operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and 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 and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. 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 health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.

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 presence of polychlorinated biphenyls (PCBs) which are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue for several years is $13,100. Transwestern has requested recovery of the portion of soil and groundwater remediation not related to PCBs in the current rate case anticipated to become effective April 2007.

Transwestern continues to incur certain costs related to PCBs that migrated into customers’ facilities. Because of the continued detection of PCBs in the customers’ facilities downstream of Transwestern’s Topock and Needles stations, Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remedial activities totaled approximately $200 for the period since acquisition. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers, and accordingly, no accrual has been established for these costs at February 28, 2007. 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 United States Environmental Protection Agency’s Spill Prevention, Control and Countermeasures (SPCC) 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

In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the “EPA”) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by HOLP was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). We have not received any follow-up correspondence from the EPA on the matter since our acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.

In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.

 

32


Table of Contents

We also assumed certain environmental remediation matters related to eleven sites in connection with our acquisition of HPL.

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 February 28, 2007 or August 31, 2006 condensed consolidated balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

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 cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

As of February 28, 2007 and August 31, 2006, an accrual on an undiscounted basis of $17,552 and $4,387, respectively, was recorded in our condensed consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition, the Transwestern acquisition, and the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors. A receivable of $388 was recorded in our condensed consolidated balance sheets as of February 28, 2007 and August 31, 2006 to account for a predecessor’s share of certain environmental liabilities of ETC OLP.

Based on information available at this time, and reviews undertaken to identify potential exposure, we believe the amount reserved for all of the above environmental matters is adequate to cover the potential exposure for clean-up costs.

In December 2003, the U.S. Department of Transportation issued a final 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.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of our current pipeline integrity testing programs, we estimate that compliance with this final rule for our existing transportation assets will result in capital costs of $7,006 during the period between the remainder of calendar year 2007 to 2008, as well as operating and maintenance costs of $8,574 during that period. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

 

17. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Accounting for Derivative Instruments and Hedging Activities

We apply Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) as amended to account for our derivative financial instruments. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying cash flow hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

Cash flows from derivatives accounted for as cash flow hedges are reported as cash flow from operating activities, in the same category as the cash flows from the items being hedged.

We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis swaps to manage our exposure to market fluctuations in the prices of natural gas and NGLs. We enter into these

 

33


Table of Contents

financial instruments with brokers who are clearing members with NYMEX and directly with counterparties in the over-the-counter (“OTC”) market. We are subject to margin deposit requirements under the OTC agreements and NYMEX positions. NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by both counterparties of the financial instrument to protect the broker from default by one of the counterparties when the financial instrument settles. We also have maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date. We had net deposits with derivative counterparties of $32,970 and $87,806 as of February 28, 2007 and August 31, 2006, respectively, reflected as deposits paid to vendors on our consolidated balance sheets.

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To reduce the impact of this price volatility, we primarily use derivative commodity instruments (futures and swaps) to manage our exposure to fluctuations in commodity prices. We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings. Furthermore, on a bi-weekly basis, management reviews the creditworthiness of the derivative counterparties to manage against the risk of default.

The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.

Non-trading Activities

We utilize various exchange-traded and over-the-counter commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL and propane prices. These contracts consist primarily of futures and swaps and are recorded at fair value on the consolidated balance sheets. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in Accumulated Other Comprehensive Income (“OCI”) until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as cash flow hedges are included in cost of products sold in the period the hedged transactions occur. Gains and losses deferred in OCI related to cash flow hedges remain in OCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For those financial derivative instruments that do not qualify for hedge accounting, the change in market value is recorded in cost of products sold in the consolidated statements of operations. We reclassified into earnings gains of $119,548 and $122,716 for the three and six months ended February 28, 2007, respectively, and gains of $142,989 and $41,675 for the three and six months ended February 28, 2006, respectively, related to commodity financial instruments that were previously reported in OCI.

We expect gains of $18,038 to be reclassified into earnings over the next twelve months related to income currently reported in OCI. The amount ultimately realized, however, will differ as commodity prices change. The majority of our commodity-related derivatives are expected to settle within the next two years.

In the course of normal operations, we routinely enter into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs, that under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using accrual accounting. For contracts that are not designated as normal purchase and sales contracts, the change in market value is recorded in costs of products sold in the consolidated statements of operations. In connection with the HPL acquisition, we acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchase and sale contracts, and therefore, are marked to market in addition to the financial options that offset them. The Black-Scholes valuation model was used to estimate the value of these embedded options.

 

34


Table of Contents

Trading Activities

Trading activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain strategies are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis contracts and gas daily contracts. The derivative contracts that are entered into for trading purposes, subject to limits, are recognized on the consolidated balance sheets at fair value. The changes in the fair value of these derivative instruments are recognized in midstream and intrastate transportation and storage revenue in the consolidated statements of operations on a net basis. Net losses associated with trading activities for the three months ended February 28, 2007 were $1,719 and net gains for the six months ended February 28, 2007 were $1,244. Included in the trading revenue was unrealized losses of $6,329 and $17,529 for the three and six months ended February 28, 2007, respectively. For the three and six months ended February 28, 2006, trading activities consisted of losses of $2,743 and gains of $49,837, respectively, including unrealized losses of $25,530 and $19,117, respectively.

The following table details the outstanding commodity-related derivatives as of February 28, 2007 and August 31, 2006, respectively:

 

February 28, 2007

   Commodity   

Notional

Volume

MMBTU

   

        Maturity        

  

Fair

Value

 

Mark to Market Derivatives

          

(Non-Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    23,023,316     2007-2009    $ 3,347  

Swing Swaps IFERC

   Gas    17,592,500     2007-2008      1,275  

Fixed Swaps/Futures

   Gas    (23,765,000 )   2007      25,294  

Forward Physical Contracts

   Gas    (4,043,550 )   2007-2008      (320 )

Options

   Gas    (602,000 )   2007-2008      742  

Forward/Swaps – in Gallons

   Propane    4,452,000     2007      (524 )

(Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    (3,880,000 )   2007-2008    $ 5,514  

Swing Swaps IFERC

   Gas    68,200     2007      (6 )

Forward Physical Contracts

   Gas    —       2007      (1,141 )

Cash Flow Hedging Derivatives

          

(Non-Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    2,282,500     2007    $ (174 )

Fixed Swaps/Futures

   Gas    2,330,000     2007      189  

 

35


Table of Contents

August 31, 2006:

                      

Mark to Market Derivatives

          

(Non-Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    33,711,140     2006-2009    $ (6,247 )

Swing Swaps IFERC

   Gas    (37,220,448 )   2006-2008      2,618  

Fixed Swaps/Futures

   Gas    3,607,500     2006-2007      (170 )

Forward Physical Contracts

   Gas    (7,986,000 )   2006-2008      (21,653 )

Options

   Gas    (1,046,000 )   2006-2008      21,653  

Forward/Swaps – in Gallons

   Propane    24,066,000     2006-2007      199  

(Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    (2,572,500 )   2006-2008    $ 21,995  

Swing Swaps IFERC

   Gas    —       2006      (31 )

Forward Physical Contracts

   Gas    (455,000 )   2006      (68 )

Cash Flow Hedging Derivatives

          

(Non-Trading)

          

Basis Swaps IFERC/NYMEX

   Gas    (34,585,000 )   2006-2007    $ (2,987 )

Fixed Swaps/Futures

   Gas    (37,872,500 )   2006-2007      2,043  

Estimates related to our gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. We also attempt to maintain balanced positions in our non-trading activities to protect ourselves 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 the gas required by our 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, will be offset with financial contracts to balance our positions. To the extent open commodity positions exist in our trading and non-trading activities, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably.

During the three months ended February 28, 2007 and 2006, the Partnership discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in the Partnership’s Bammel storage facilities. The discontinuation resulted from management’s determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable of occurring by the end of the originally specified time period, or within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during February through March. One of the key criteria to achieve hedge accounting under SFAS 133 is that the forecasted transaction be probable of occurring as originally set forth in the hedge documentation. As a result, during the three months ended February 28, 2007 and 2006, the Partnership recognized previously deferred unrealized gains of $17,848 and $84,680 from the discontinued application of hedge accounting, which is included in the reclassification into earnings from OCI during the three and six months ended February 28, 2007 and 2006, respectively. The Partnership classified the $17,848 and $84,680 as costs of products sold in its consolidated statements of operations.

Interest Rate Risk

We are exposed to market risk for changes in interest rates related to our bank credit facilities. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements which allow us to effectively convert a portion of variable rate debt into fixed rate debt.

We entered into treasury locks and interest rate swaps with a notional amount of $300,000 during the third fiscal quarter of 2006. We elected to not apply hedge accounting to these financial instruments. Accordingly, changes in the fair value of these instruments are recorded as interest expense on the consolidated statements of operations. These instruments settled during the six months ended February 28, 2007 for a gain of $567.

We entered into forward starting interest swaps with a notional value of $400,000 during the three months ended August 31, 2006. The fair value of the swaps was recorded as a liability of $14,955 and $8,699 on the consolidated balance sheets as of February 28, 2007 and August 31, 2006, respectively. The swaps were accounted for as cash

 

36


Table of Contents

flow hedges under SFAS 133 and recorded as a component of OCI, to be reclassified to interest expense in the future as the related interest payments are made. These interest swaps were terminated subsequent to February 28, 2007 at a cost of approximately $13,400.

The Parent Company had 10 year interest rate swaps with a notional amount of $300,000 outstanding as of February 28, 2007. We elected to not apply hedge accounting to these financial instruments, accordingly, changes in fair value are accounted for in interest expense on the condensed consolidated statements of operations. The swaps had a net fair value of a liability of $4,800 and $404 as of February 28, 2007 and August 31, 2006, respectively, which was recorded as a component of price risk management assets and liabilities on the condensed consolidated balance sheets.

In connection with the Titan acquisition, we assumed a three year LIBOR interest rate swap with a notional amount of $125,000. The fair value of this swap as of February 28, 2007, and August 31, 2006 was a net liability and asset of $425 and $519, respectively, and was recorded as a component of price risk management assets and liabilities in the consolidated balance sheet. We elected to not apply hedge accounting to these financial instruments. Accordingly, changes in the fair value of these instruments are recorded as interest expense on the condensed consolidated statements of operations.

The Parent Company entered into interest rate swaps with an aggregate notional amount of $1,200,000 during the three months ended February 28, 2007. The Partnership elected to apply hedge accounting under SFAS 133 to swaps with a notional amount of $700,000. The remaining notional amount of $500,000 in swaps included a put option exercisable in 2010 and did not receive hedge accounting. The fair value of these swaps was a net asset of $3,744 as of February 28, 2007.

We reclassified into earnings gains of $3,482 and $769 for the three and six months ended February 28, 2007, respectively, related to interest rate swaps that were previously reported in OCI. Losses of $8 and gains of $756 were reclassified into earnings for the three and six months ended February 28, 2006 related to interest rate swaps previously reported in OCI. We expect gains of $1,974 to be reclassified into earnings over the next twelve months related to income on interest rate financial instruments currently reported in OCI. The amount ultimately realized, however, will differ as interest rates change.

The following represents gains (losses) on derivative activity for the periods presented:

 

     Three Months Ended
February 28,
    Six Months Ended
February 28,
 
     2007     2006     2007     2006  

Commodity-related

        

Unrealized gains (losses) recognized in revenues and cost of products sold related to commodity-related derivative activity excluding ineffectiveness

   $ 23,817     $ (35,744 )   $ 15,885     $ 37,809  

Ineffective portion of derivatives qualifying for hedge accounting

     (1,103 )     35,645       1,482       17,323  

Realized gains included in revenues and cost of products sold

     102,889       109,748       113,866       100,455  

Interest rate swaps

        

Unrealized gains (losses) on interest rate swap included in interest expense, excluding ineffectiveness

   $ 5,981     $ —       $ (4,000 )   $ (151 )

Ineffective portion of derivatives qualifying for hedge accounting

     (2,390 )     —         (436 )     771  

Realized gains (losses) on interest rate swap included in interest expense

     1,566       (8 )     2,592       135  

Credit Risk

We maintain credit policies with regard to our counterparties that we believe significantly 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 its overall exposure to credit risk, either positively or

 

37


Table of Contents

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 financial position or results of operations as a result of counterparty performance.

 

18. RELATED PARTY TRANSACTIONS:

Related company receivables and payables as of February 28, 2007 and August 31, 2006 relate to activities in the normal course of business and such amounts are immaterial.

As of February 28, 2007 and August 31, 2006, we had advances due from a propane joint venture of $7,804 and $3,775, respectively, which are included in intangibles and other long-term assets on our condensed consolidated balance sheets.

Our natural gas midstream and intrastate transportation and storage operations secure compression services from third parties including Energy Transfer Technologies, Ltd., of which Energy Transfer Group, LLC is the General Partner. These entities are collectively referred to as the “ETG Entities”. Our Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of the General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of independent directors of the General Partner, no less favorable than those available from other providers of compression services. During the six months ended February 28, 2007 and 2006, we made payments totaling $848 and $1,813, respectively, to the ETG Entities for compression services provided to and utilized in our natural gas midstream and intrastate transportation and storage operations. As of February 28, 2007 and August 31, 2006, accounts payable to ETG related to compressor leases were not significant.

ETE’s general partner will receive a $500 per year management fee for the management of the Partnership’s operations and activities. Under the terms of the shared services agreement, the Partnership will also pay ETP an annual administrative fee of $500 for the provision of various general and administrative services for ETE’s benefit. The administrative fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index and may also increase if ETE makes an acquisition that requires an increase in the level of general and administrative services that the Partnership receives from its general partner or its affiliates. Fees paid under this agreement during the three months ended February 28, 2007 were nominal.

See Notes 3 and 15 for discussion of other related party transactions with ETP and ETI.

 

19. REPORTABLE SEGMENTS:

As of February 28, 2007, our financial statements reflect five reportable segments:

ETC OLP:

 

   

midstream operations

 

   

intrastate transportation and storage operations

ET Interstate:

 

   

interstate transportation operations

HOLP and Titan:

 

   

retail propane operations

HOLP:

 

   

wholesale propane operations, including the operations of MP Energy Partnership

As of December 1, 2006, with the completion of our acquisition of Transwestern, we have a new reporting segment for our interstate transportation operations. As a result, the comparability of the segment operations information is affected by this addition. The volumes and results of operations data for the three months ended February 28, 2007 include the interstate operations for the entire period. However, the three and six month volumes and results of operations do not include the interstate operations for periods prior to December 1, 2006.

Segments below the quantitative thresholds are classified as “other”. None of the components of the “other” segment have ever met any of the quantitative thresholds for determining reportable segments. Management has combined the domestic wholesale propane and foreign wholesale propane segments into one segment for all periods presented in this report. The combined segment is referred to as the wholesale propane segment.

 

38


Table of Contents

Midstream and transportation and storage segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

The midstream operations focus on the gathering, compression, treating, blending, processing, and marketing of natural gas, primarily on or through the Southeast Texas System, and marketing operations related to our producer services business. Revenue is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through our pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices.

The intrastate transportation and storage operations focus on transporting natural gas through our Oasis Pipeline, ET Fuel System, East Texas Pipeline System, HPL System and Fort Worth Basin Pipeline. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are high. The transportation and storage operations also consist of the HPL System which generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. The use of the Bammel storage reservoir allows us to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. The HPL System also transports natural gas for a variety of third party customers.

The interstate transportation operations focus on natural gas transportation of Transwestern, which owns and operates approximately 2,400 miles of interstate natural gas pipeline system extending from Texas and Oklahoma, through the San Juan Basin to the California border. Transwestern is a major natural gas transporter to the California border and delivers natural gas from the east end of its system to Texas intrastate and Midwest markets. The revenues of this segment consist primarily of fees earned from natural gas transportation services and operational gas sales from excess gas retained.

Our retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. We manage our propane segments separately as each segment involves different distribution, sale, and marketing strategies.

We evaluate the performance of our operating segments based on operating income exclusive of general partnership selling, general, administrative expenses, gain (loss) on disposal of assets, minority interests, interest expense, earnings (losses) from equity investments and income tax expense (benefit). Certain overhead costs relating to a reportable segment have been allocated for purposes of calculating operating income. Effective with the Transwestern acquisition on December 1, 2006, we began allocating administration expenses to our operating partnerships. The amounts of such allocations for the three and six months ended February 28, 2007 were approximately $1,700 to midstream, $1,500 to interstate transportation and $2,500 to propane, for a total of approximately $5,700.

The following table presents the financial information by segment for the following periods:

 

39


Table of Contents
    

Three Months Ended

February 28,

   

Six Months Ended

February 28,

 
     2007     2006     2007     2006  

Volumes: (unaudited)

        

Midstream

        

Natural gas MMBtu/d – sold

     819,611       1,529,856       900,238       1,528,616  

NGLs bbls/d – sold

     15,901       9,537       13,723       9,879  

Transportation and storage

        

Natural gas MMBtu/d – transported

     5,030,631       4,231,797       4,918,191       4,349,137  

Natural gas MMBtu/d – sold

     1,655,278       1,868,486       1,481,724       1,709,049  

Interstate transportation

        

Natural gas MMBtu/d – transported

     1,728,056       —         1,728,056       —    

Propane gallons (in thousands)

        

Retail

     253,715       165,758       394,346       254,496  

Wholesale

     32,428       28,243       55,711       47,844  
                                

Total gallons

     286,143       194,001       450,057       302,340  
                                
    

Three Months Ended

February 28,

   

Six Months Ended

February 28,

 
     2007     2006     2007     2006  

Revenues:

        

Midstream

   $ 624,245     $ 1,205,027     $ 1,232,428     $ 2,754,855  

Eliminations

     (297,620 )     (611,989 )     (654,212 )     (1,518,793 )

Intrastate transportation and storage

     1,108,055       1,490,265       1,918,908       3,055,775  

Interstate transportation (see Note 3)

     58,158       —         58,158       —    

Retail propane and other propane related

     529,555       332,147       824,794       514,178  

Wholesale propane

     39,209       32,958       68,246       56,899  

Other

     878       1,408       2,603       3,522  
                                

Total revenues

   $ 2,062,480     $ 2,449,816     $ 3,450,925     $ 4,866,436  
                                

Cost of Sales:

        

Midstream

   $ 573,712     $ 1,160,557     $ 1,132,430     $ 2,597,427  

Eliminations

     (297,620 )     (611,989 )     (654,212 )     (1,518,793 )

Intrastate transportation and storage

     862,617       1,236,485       1,544,474       2,665,788  

Retail propane and other propane related

     311,364       193,845       486,714       302,315  

Wholesale propane

     35,684       29,426       63,225       51,711  

Other

     59       507       528       1,010  
                                

Total cost of sales

   $ 1,485,816     $ 2,008,831     $ 2,573,159     $ 4,099,458  
                                

 

40


Table of Contents

Depreciation and Amortization:

        

Midstream

   $ 6,550     $ 4,866     $ 12,155     $ 9,536  

Intrastate transportation and storage

     14,083       13,131       28,449       24,934  

Interstate transportation

     9,654       —         9,654       —    

Retail propane and other propane related

     17,937       13,744       34,528       26,954  

Wholesale propane

     191       223       368       407  

Other

     —         106       125       206  
                                

Total depreciation and amortization

   $ 48,415     $ 32,070     $ 85,279     $ 62,037  
                                

Operating income (loss):

        

Midstream

   $ 24,063     $ 25,870     $ 54,647     $ 118,893  

Intrastate transportation and storage

     180,745       186,088       240,475       253,292  

Interstate transportation

     34,112       —         34,112       —    

Retail propane and other propane related

     114,314       70,255       132,172       80,734  

Wholesale propane

     1,247       1,825       1,545       2,207  

Other

     419       (68 )     373       220  

Selling general and administrative expenses not allocated to segments

     (3,049 )     (60,257 )     (8,386 )     (63,767 )
                                

Total operating income

     351,851       223,713       454,938       391,579  
                                

Other items not allocated by segment:

        

Interest expense

     (65,077 )     (39,096 )     (133,624 )     (78,239 )

Equity in earnings (losses) of affiliates

     (514 )     106       4,373       (168 )

Gain (loss) on disposal of assets

     (3,229 )     662       (1,285 )     534  

Loss on extinguishment of debt

     —         (5,060 )     —         (5,060 )

Interest and other income, net

     1,652       2,432       3,169       3,496  

Income tax expense

     (2,576 )     (3,289 )     (5,449 )     (24,976 )

Minority interests

     (134,751 )     (155,033 )     (143,726 )     (223,130 )
                                
     (204,495 )     (199,278 )     (276,542 )     (327,543 )
                                

Net income

   $ 147,356     $ 24,435     $ 178,396     $ 64,036  
                                
                

Six Months Ended

February 28,

 
                 2007     2006  

Additions to Property, Plant and Equipment, including acquisitions (accrual basis):

        

Midstream

       $ 114,005     $ 10,245  

Intrastate transportation and storage

         456,785       235,391  

Interstate transportation

         1,269,051       —    

Retail propane and other propane related

         44,503       32,554  

Wholesale propane

         30       298  

Other

         839       1,973  
                    

Total

       $ 1,885,213     $ 280,461  
                    

 

41


Table of Contents
               February 28,    August 31,
               2007    2006

Total Assets:

           

Midstream

         $ 786,997    $ 828,770

Intrastate transportation and storage

           3,519,898      3,317,781

Interstate transportation

           1,554,586      —  

Retail propane and other propane related

           1,727,385      1,619,732

Wholesale propane

           37,009      39,816

Other

           161,358      118,042
                   

Total

         $ 7,787,233    $ 5,924,141
                   

 

20. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the stand-alone financial statements of the Parent Company as of February 28, 2007 and August 31, 2006 and for the three and six-month periods ended February 28, 2007 and 2006 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:

 

42


Table of Contents

BALANCE SHEETS

 

    

February 28,

2007

   

August 31,

2006

 

ASSETS

    

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 13,962     $ 135  

Accounts receivable from related companies

     22,202       752  

Price risk management assets

     3,806       711  

Prepaid expenses and other

     644       301  
                

Total current assets

     40,614       1,899  

ADVANCES TO AND INVESTMENT IN AFFILIATES

     1,505,870       663,245  

INTANGIBLES AND OTHER ASSETS, net

     14,106       3,344  
                

Total assets

   $ 1,560,590     $ 668,488  
                

LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)

    

CURRENT LIABILITIES:

    

Accounts payable

   $ —       $ 386  

Accounts payable to affiliates

     1,006       736  

Accrued interest

     15,797       4,105  

Accrued and other current liabilities

     1,596       104  
                

Total current liabilities

     18,399       5,331  

LONG-TERM DEBT, less current maturities

     1,726,500       616,291  

OTHER NON-CURRENT LIABILITIES

     4,268       1,115  

COMMITMENTS AND CONTINGENCIES

    
                
     1,749,167       622,737  
                

PARTNERS’ CAPITAL (DEFICIT):

    

General Partner

     91       (69 )

Limited Partners

    

Common Unitholders

     (250,817 )     (9,586 )

Class B Unitholders

     53,715       53,130  

Accumulated other comprehensive income

     8,434       2,276  
                

Total partners’ capital (deficit)

     (188,577 )     45,751  
                

Total liabilities and partners’ capital (deficit)

   $ 1,560,590     $ 668,488  
                

 

43


Table of Contents

STATEMENTS OF OPERATIONS

 

    

Three Months Ended

February 28,

   

Six Months Ended

February 28,

 
     2007     2006     2007     2006  

SELLING, GENERAL AND ADMINISTRATIVE EXPENSE

   $ (3,609 )   $ (54,067 )   $ (5,308 )   $ (54,756 )

OTHER INCOME (EXPENSE):

        

Equity in earnings of affiliates

     174,790       93,948       234,769       144,881  

Interest expense

     (24,299 )     (10,555 )     (51,379 )     (21,299 )

Loss on extinguishment of debt

     —         (5,060 )     —         (5,060 )

Other, net

     474       169       314       270  
                                

NET INCOME

     147,356       24,435       178,396       64,036  

GENERAL PARTNER’S INTEREST IN NET INCOME

     467       144       612       392  
                                

LIMITED PARTNERS’ INTEREST IN NET INCOME

   $ 146,889     $ 24,291     $ 177,784     $ 63,644  
                                

 

44


Table of Contents

STATEMENTS OF CASH FLOWS

 

    

Six Months Ended

February 28,

 
     2007     2006  

CASH FLOWS FROM OPERATING ACTIVITIES:

    

Net income

   $ 178,396     $ 64,036  

Undistributed earnings of affiliates

     (84,935 )     (78,544 )

Change in operating assets and liabilities

     (6,739 )     (481 )

Non-cash compensation on unit grants

     9       52,953  

Amortization of finance costs charged to interest

     1,128       —    
                

Net cash flows provided by operating activities

     87,859       37,964  
                

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Cash invested in subsidiaries

     (1,200,000 )     (132,387 )

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Proceeds from borrowings

     1,252,176       —    

Principal payments on debt

     (212,659 )     (223,000 )

Equity offering

     212,455       474,741  

Redemption of Common Units in IPO

     —         (131,620 )

Cash distributions to partners

     (114,152 )     (34,225 )

Debt issuance costs

     (11,852 )     —    
                

Net cash provided by financing activities

     1,125,968       85,896  
                

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     13,827       (8,527 )

CASH AND CASH EQUIVALENTS, beginning of period

     135       8,527  
                

CASH AND CASH EQUIVALENTS, end of period

   $ 13,962     $ —    
                

 

45


Table of Contents
21. SUBSEQUENT EVENTS:

On March 2, 2007 the Parent Company issued approximately 5.0 million Common Units in a private placement to a group of institutional investors. The units were issued at a price of $31.96 per unit resulting in net proceeds of approximately $160,000 to the Parent Company. The proceeds were used to repay Parent Company indebtedness. Investors were granted registration rights with respect to these units.

In March 2007 ETP entered into interest rate swaps with an aggregate notional amount of $600,000 with various financial institutions in anticipation of a debt offering in the fourth fiscal quarter of 2007.

On May 1, 2007, ETP will hold a special meeting of its Common Unitholders, entitled to vote as of the record date of April 2, 2007, to approve (i) a change in the terms of the Partnership’s Class G Units to provide that each Class G Unit is convertible into one Common Unit and (ii) the issuance of additional Common Units upon such conversion.

The conversion of these Class G Units would be on a one-to-one basis, resulting in a greater number of Common Units outstanding, but not an increase in the overall number of ETP units. Accordingly, on an overall basis, the conversion would not be dilutive to the Partnership’s existing Common Unitholders. The Board of Directors has recommended that ETP’s Common Unitholders approve these matters.

 

46


Table of Contents

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

AND RESULTS OF OPERATIONS

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

Energy Transfer Equity, L.P. is a Delaware limited partnership, whose Common Units are publicly traded on the New York Stock Exchange (“NYSE”) under the ticker symbol “ETE”. ETE was formed in September 2002 and completed its IPO of 24,150,000 Common Units in February 2006.

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 fiscal year ended August 31, 2006 filed with the Securities and Exchange Commission on November 29, 2006. 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.

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

Overview

Currently, the Parent Company’s business operations are conducted only through ETP’s wholly-owned subsidiary Operating Partnerships, ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and natural gas storage operations, Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”), a Delaware limited liability company engaged in interstate transportation of natural gas, HOLP, a Delaware limited partnership engaged in retail and wholesale propane operations, and Titan, a Delaware limited partnership engaged in retail propane operations. ETC OLP, Transwestern, HOLP and Titan are collectively referred to as “the Operating Partnerships”.

Parent Company – Energy Transfer Equity, L.P.

The principal sources of cash flow for the Parent Company are distributions it receives from its direct and indirect investments in limited and general partner interests of ETP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service and distributions to its general and limited partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP or the Operating Partnerships.

The Parent Company’s long-term debt increased significantly during the six months ended February 28, 2007 as a result of debt incurred to finance the acquisition of Class G limited partner units of ETP. The purchase of Class G Units increased the Parent Company’s ownership of ETP limited partner interests from approximately 33% to approximately 46%.

In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.

Consolidated Operations

Midstream and Intrastate Transportation and Storage Segments

Through ETC OLP, we own and operate intrastate natural gas gathering and transportation pipelines, natural gas treating and processing assets located in Texas and Louisiana, and three natural gas storage facilities located in Texas. These assets include approximately 12,200 miles of intrastate pipeline in service, with an additional 500 miles of intrastate pipeline under construction.

 

47


Table of Contents

Our midstream segment results are derived primarily from margins we realize for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems, processed at our processing and treating facilities, and the volumes of NGLs processed at our facilities. We also market natural gas on our pipeline systems in addition to other pipeline systems to realize incremental revenue on gas purchased, increase pipeline utilization and provide other services that are valued by our customers. In addition and in accordance with our commodity risk management policy, we generate income from limited trading activities. Our trading activities include purchasing and selling natural gas and the use of financial instruments, including basis and gas daily contracts.

Our intrastate transportation and storage segment consists of natural gas gathering and intrastate transportation pipelines as well as three natural gas storage facilities with approximately 78 Bcf in storage capacity. The results from our transportation and storage segment are primarily derived from the fees we charge to transport natural gas on our pipelines, including a fuel retention component. We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL System. Generally, HPL purchases its natural gas from either the market (including purchases from our midstream segment’s producer services) and from producers at the wellhead. To the extent the natural gas comes from producers, it is purchased at a discount to a specified price and resold to customers at the index price.

We also utilize our Bammel storage reservoir to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin.

As a result of our trading activities and the use of derivative financial instruments that may not qualify for hedge accounting in our midstream and transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk management committee, which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy as discussed in Note 17 in the accompanying condensed consolidated financial statements.

Interstate Transportation Segment

In connection with the acquisition of Transwestern on December 1, 2006, we also own 2,400 miles of interstate pipelines. The operating results for Transwestern are included in our results on a consolidated basis as of the acquisition date (December 1, 2006).

Transwestern is an open-access natural gas interstate pipeline extending approximately 2,400 miles from the gas producing regions of West Texas, Oklahoma, eastern and northwest New Mexico and southern Colorado primarily to pipeline interconnects off the east end of its system and to the California market. Transwestern has access to three significant gas basins: the Permin Basin in West Texas and eastern New Mexico; the San Juan Basin in northwest New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle.

Natural gas sources from the San Juan basin and surrounding producing areas can be delivered to connecting pipelines and natural gas market hubs in the east as well as markets to the west like California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

Transwestern earns the majority of its revenue by entering into firm transportation contracts, reserving capacity for customers to transport natural gas in its pipelines, whereby customers pay for the transportation capacity on a system regardless of whether it is utilized. It also earns variable revenue from charges assessed on each unit of transportation provided. In addition, to the extent that the gas retained by Transwestern for the operation of its pipeline system is not consumed in its systems’ compressors, it is sold as operational gas when conditions warrant.

FERC regulates our interstate natural gas pipeline interests. Transwestern transports natural gas in interstate commerce. As a result, Transwestern qualifies as a “natural gas company” under the Natural Gas Act and is subject to the regulatory jurisdiction of FERC. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:

 

 

rate structures;

 

 

rates of return on equity;

 

 

recovery of costs;

 

 

the services that our regulated assets are permitted to perform;

 

48


Table of Contents
 

the acquisition, construction and disposition of assets; and

 

 

to an extent, the level of competition in that regulated industry.

Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against Transwestern’s FERC-approved rates could have an adverse impact on our revenues associated with providing transmission services on Transwestern’s pipelines.

Retail and Wholesale Propane Segments

Our propane related segments are operated by HOLP, Titan and their respective subsidiaries engaged in the sale, distribution and marketing of propane and other related products through their retail and wholesale segments, (the propane segments). HOLP and Titan derive their revenue primarily from the retail propane segment. We believe that we are the third largest retail propane marketer in the United States, based on retail gallons sold. We serve more than one million propane customers from 442 customer service locations in 41 states.

The propane segments are margin-based businesses in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which we have no control. Product supply contracts are generally one-year agreements subject to annual renewal and generally permit suppliers to charge posted prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the wholesale cost of propane may not be immediately passed on to retail customers, such increases could reduce gross profits. We generally have attempted to reduce price risk by purchasing propane on a short-term basis. We have on occasion purchased for future resale significant volumes of propane for storage during periods of low demand, which generally occur during the summer months, at the then current market price, both at our customer service locations and in major storage facilities. In particular, our propane business is largely seasonal and dependent upon weather conditions in our service areas.

Historically, approximately two-thirds of our retail propane volume and substantially all of our propane-related operating income is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and operating profits for the propane segments are concentrated in our first and second fiscal quarters; however, cash flow from operations is generally greatest during our second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to industrial and agricultural customers are much less weather sensitive.

A substantial portion of our propane is used in the heating-sensitive residential and commercial markets causing the temperatures in our areas of operations, particularly during the six-month peak-heating season, to have a significant effect on the financial performance of our propane operations. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. We use information about normal temperatures to help us understand how temperatures that are colder or warmer than normal affect historical results of operations and in preparing forecasts related to our future operations.

The retail propane segment’s gross profit margins are not only affected by weather patterns, but also vary according to customer mix. Sales to residential customers generate higher margins than sales to certain other customer groups, such as commercial or agricultural customers. The wholesale propane segment’s margins are substantially lower than retail margins. In addition, propane gross profit margins vary by geographical region. Accordingly, a change in customer or geographic mix can affect propane gross profit without necessarily affecting total revenues.

 

49


Table of Contents

Amounts discussed below reflect 100% of the results of MP Energy Partnership, a Canadian general partnership in which HOLP owns a 60% interest.

Trends and Outlook

We believe our natural gas operations are positioned to provide increasing operating results based on the current levels of contracted and expected capacity to be taken by our customers, our expansion plans that we expect to complete in fiscal year 2007, and incremental earnings related to the recently acquired Transwestern operations.

We also expect our propane-related segment to realize overall volume increases during fiscal year 2007 due to the effects of the Titan acquisition. However, continued warmer than normal weather will negatively impact volumes. We expect to be able to offset the impact of weather-related reduced volumes with reduced operating costs and improved gross margins to the extent our marketplace will allow it. We also plan to continue our active propane acquisition strategy and to expand our internal growth initiatives.

Recent Developments

Transwestern Pipeline. On November 1, 2006, pursuant to agreements entered into with GE Energy Financial Services (“GE”) and Southern Union Company (“Southern Union”), we acquired the member interests in CCE Holdings, LLC (“CCEH”) from GE and certain other investors for $1.0 billion. We financed a portion of the CCEH purchase price with the proceeds from our issuance of approximately 26.1 million Class G Units to Energy Transfer Equity, L.P. simultaneous with the closing on November 1, 2006. The member interests acquired represented a 50% ownership in CCEH.

On December 1, 2006, in a second and related transaction, CCEH redeemed ETP’s 50% interest ownership in CCEH in exchange for 100% ownership of Transwestern Pipeline Company, LLC (“Transwestern”) which owns the Transwestern Pipeline, a 2,400 mile interstate natural gas pipeline. Following the final step, Transwestern became a new operating subsidiary and separate segment of ETP. Our total acquisition cost for Transwestern, including assumed debt, was approximately $1.537 billion, including our basis of $956.3 million in CCEH (see Note 3 to the condensed consolidated financial statements).

Midcontinent Express Pipeline. On December 13, 2006, we announced that we had entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of the Midcontinent Express Pipeline (“MEP”). The approximately 500-mile pipeline, which will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco in Butler, Alabama, will have an initial capacity of 1.4 Bcf per day. Pending necessary regulatory approvals, the approximately $1.3 billion pipeline project is expected to be in service by February 2009. MEP has prearranged binding commitments from multiple shippers for 800,000 dekatherms per day which includes a binding commitment from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation for 500,000 dekatherms per day. MEP has executed a firm capacity lease agreement for up to 500,000 dekatherms per day with Enogex, a subsidiary of OGE Energy, an Oklahoma intrastate pipeline, to provide a seamless transportation path from various locations in Oklahoma into and through MEP. The new pipeline will also interconnect with Natural Gas Pipeline Company of America, a wholly-owned subsidiary of Kinder Morgan, Inc., and with our previously announced 36-inch pipeline extending from the Barnett Shale and interconnecting with our Texoma pipeline near Paris, Texas.

42-inch Pipeline Project. On March 29, 2007 the Partnership announced the completion of the final phase of its 42-inch pipeline construction project. This final phase connects the Partnership’s 36-inch North Texas Pipeline (NTP), the Partnership’s Barnett Shale pipeline system, and the Partnership’s Bethel Storage Facility to the Carthage Hub and other intrastate and interstate pipelines. This phase completes the previously announced 243 mile 42-inch pipeline project and provides the Partnership and its customers with over 1 Bcf of additional take-away capacity out of the Barnett Shale and Bossier Sands producing areas of Texas.

The completion of the 42-inch pipeline establishes the Partnership as the leader in the intrastate pipeline arena with connections to Texas’ major marketing hubs including Katy, Waha, Carthage, Houston Ship Channel and Agua Dulce, as well as to the city gates of Texas’ major cities, including Houston, San Antonio, Austin and Dallas-Ft. Worth. The 42-inch pipeline provides cities, Ship Channel markets, power plants and other consumers throughout the State with significantly greater access to the major producing regions in Texas including the Permian Basin, the Gulf Coast, the Barnett Shale, the Austin Chalk and the Bossier Sands. With this 42-inch completion, the Partnership is capable of providing producers in Texas with unprecedented market flexibility to access both intrastate and interstate pipelines.

 

50


Table of Contents

The Partnership will begin construction this summer of its next previously announced 42-inch pipeline project, the Southeast Bossier 42-inch Expansion. This project consists of approximately 157 miles of predominately 42-inch pipe connecting the Partnerships 30-inch and 42-inch pipelines with the 30-inch Texoma line north of Beaumont. The Southeast Bossier 42-inch Expansion is expected to be completed by the 1st calendar quarter of 2008.

North Texas Gathering System. In December 2006 we purchased a gathering system in north Texas for $32 million. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $21 million to be determined two years after the closing date. We will record the required adjustment to the purchase price allocation when the amount of the actual contingent consideration is determinable beyond a reasonable doubt. The gathering system consists of approximately 36 miles of pipeline and has an estimated capacity of 70 MMcf/d. We expect the gathering system will allow us to continue expanding in the Barnett Shale area of north Texas.

Rate Case. 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. On October 31, 2006, in Docket No. RP06-614 the FERC issued its Order Accepting and Suspending Tariff Sheets Subject to Refund and Establishing a Hearing and Technical Conference (Commission’s October 31, 2006 Order). In this Order the Commission accepted and suspended the revised tariff sheets for the maximum five-month statutory period to be effective April 1, 2007, subject to refund, and subject to the outcome of a hearing established by this order. Transwestern and the active parties in this proceeding engaged in settlement negotiations to resolve all issues set for hearing by the Commission’s October 31, 2006 Order. On March 9, 2007, Transwestern filed with the FERC its Stipulation and Agreement of Settlement (Stipulation and Agreement) which, if approved by the commission, will settle these matters. The Stipulation provides for (i) revised base tariff rates, (ii) the amortization of certain costs, including the Enron Cash Balance Plan, regulatory commission expense, post retirement benefits, the accumulated reserve adjustment regulatory asset, deferred income taxes, and certain non-PCB environmental costs, and (iii) a depreciation rate of 1.20 percent for all transmission plant facilities.

Analytical Analysis

The comparability of our condensed consolidated financial statements is affected by the Parent Company’s purchase of Common Units and Class F Units (subsequently converted to Common Units) of ETP in February 2006, the Parent Company’s purchase of Class G Units of ETP in November 2006, ETP’s 100% acquisition of Transwestern on December 1, 2006, and the acquisitions of 50% of CCEH in November 2006 and Titan in June 2006 (see Note 3 to our condensed consolidated financial statements). The comparability is also affected by natural gas prices, mainly in our producer services’ revenues and natural gas sales on our HPL system. Excluding the impact from volumetric changes, our revenues in these areas are affected by changes in natural gas prices. Since we buy and sell natural gas primarily based on either first of month index prices, gas daily average prices or a combination of both, our revenues tend to be higher when natural gas prices are high and our revenues tend to be lower when natural gas prices are lower. However, a change in natural gas prices is only one of several elements that impact our overall margin. Other factors include, but are not limited to, volumetric changes, our hedging strategies and the use of financial instruments, fee-based revenues, trading activities, and basis differences between market hubs.

The acquisition of Transwestern resulted in a significant increase in our property, plant and equipment, intangible assets and goodwill from August 31, 2006 to February 28, 2007 (see Note 3 to the condensed consolidated financial statements). The increase from August 31, 2006 to February 28, 2007 in our long-term debt was due to the Transwestern acquisition and borrowings to finance the Parent Company’s purchase of Class G Units from ETP.

A summary of the effect on the Parent Company’s ownership of ETP limited partner interests through the unit acquisitions noted above is as follows:

 

 

February 2006 – The purchase of 1,069,850 Common and 2,570,150 Class F Units increased the ownership of limited partner interests from approximately 31% to approximately 33%.

 

 

November 2006 – The purchase of 26,086,950 Class G Units increased the ownership of limited partner interests from approximately 33% to approximately 46%.

ETP is consolidated in the accompanying financial statements. As a result, the effect of these transactions is reflected primarily in the “minority interest” caption on the condensed consolidated balance sheets and results of operations.

 

51


Table of Contents

Operating Data

Comparative Results for the Three and Six Months Ended February 28, 2007 and 2006

Volumes of natural gas sales, NGL sales including propane, and natural gas transported by our midstream, intrastate transportation and storage, retail propane, and wholesale propane segments are as follows:

Midstream

 

    

Three Months Ended

February 28,

   Increase    

Six Months Ended

February 28,

   Increase  
     2007    2006    (Decrease)     2007    2006    (Decrease)  

Natural gas MMBtu/d

   819,611    1,529,856    (710,245 )   900,238    1,528,616    (628,378 )

NGLs Bbls/d

   15,901    9,537    6,364     13,723    9,879    3,844  

 

 

For the three months ended February 28, 2007, the decrease in natural gas volumes was principally due to less favorable market conditions during the fiscal 2007 period resulting in lower sales volumes conducted by our producer services’ operations. Our NGL sales volumes vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The increase in NGL sales volumes is principally due to favorable market conditions to process and extract NGLs during the three months ended February 28, 2007 compared to the same period last year and the completion of our Johnson County processing plants during the 2007 fiscal period.

For the six months ended February 28, 2007, the decrease in natural gas volumes was principally due to less favorable market conditions during the fiscal 2007 period. The increase in NGL sales volumes is principally due to favorable market conditions to process and extract NGLs during the 2007 fiscal period compared to the same period last year and the completion of our Johnson County processing plants in the 2007 fiscal period.

Intrastate Transportation and Storage

 

    

Three Months Ended

February 28,

   Increase    

Six Months Ended

February 28,

   Increase  
     2007    2006    (Decrease)     2007    2006    (Decrease)  

Natural gas MMBtu/d – transported

   5,030,631    4,231,797    798,834     4,918,191    4,349,137    569,054  

Natural gas MMBtu/d – sold

   1,655,278    1,868,486    (213,208 )   1,481,724    1,709,049    (227,325 )

 

 

For the three months ended February 28, 2007, transported natural gas volumes increased principally due to the increased volumes experienced on the ET Fuel system and East Texas Pipeline system as a result of the continued efforts to secure long-term shipper contracts and the completion of phase I of the 42-inch pipeline project in late August 2006 and phase II in December 2006. Natural gas sales volumes on the HPL System for the three months ended February 28, 2007 decreased principally due to less volumes sold to east Texas markets as a result of lower price differentials.

For the six months ended February 28, 2007, transported natural gas volumes increased due to the increased volumes transported on the ET Fuel System and East Texas Pipeline system as a result of our continued efforts to secure more long-term shipper contracts and the completion of phase I and II of the 42-inch pipeline project. Natural gas sales volumes on the HPL System for the six months ended February 28, 2007 decreased principally due to less volumes sold to east Texas markets as a result of lower price differentials.

 

52


Table of Contents

Interstate Transportation

 

    

Three Months Ended

February 28,

       

Six Months Ended

February 28,

    
     2007    2006    Increase    2007    2006    Increase

Natural gas MMBtu/d – transported

   1,728,056    —      1,728,056    1,728,056    —      1,728,056

The increase was due to the 100% acquisition of Transwestern on December 1, 2006.

Propane

 

     Three Months Ended
February 28,
        Six Months Ended
February 28,
    
     2007    2006    Increase    2007    2006    Increase

Propane gallons sold

                 

(in thousands)

                 

Retail

   253,715    165,758    87,957    394,346    254,496    139,850

Wholesale

   32,428    28,243    4,185    55,711    47,844    7,867

Retail Propane. The retail propane operations continue to reflect significant increases in gallons sold in the three and six months ended February 28, 2007 as compared to the three and six months ended February 28, 2006 due to the Titan acquisition in June 2006. Synergies and blending operations have taken place over the course of the past six months with this acquisition to gain efficiencies and cost savings. Titan locations that are identifiable as operating on a stand-alone basis contributed 71.8 million and 112.9 million of the net gallon increase in retail propane gallons sold for the three and six months ended February 28, 2007, respectively, compared to the three and six months ended February 28, 2006. The remainder of the increased volumes is attributed to the increased volumes in the blended locations from the Titan acquisition, other acquisition related volumes, colder weather experienced during the second quarter and to a lesser extent, internal growth. The overall weather in our areas of operations during the three months ended February 28, 2007 was 4.8% colder than the three months ended February 28, 2006 and 4.7% warmer than normal. For the six months ended February 28, 2007, weather was 6.8% colder than the six months ended February 28, 2006 and 4.4% warmer than normal. Our diversified West to East operations throughout the United States allows us to help balance weather patterns capturing the favorable heating degree days as the colder weather travels across the country.

Wholesale Propane. For the three months ended February 28, 2007, sales of wholesale propane gallons increased by 4.2 million gallons compared to the three months ended February 28, 2006. The increase is due to an increase of 5.3 million gallons in our Canadian wholesale operations related to increased marketing efforts in our Canadian operations, offset by a decrease of 1.1 million gallons sold in our U.S. wholesale operations.

For the six months ended February 28, 2007, wholesale propane gallons increased by 7.9 million gallons compared to the same period in 2006. Of this increase, 10.4 million is due to an increase in gallons sold in our foreign wholesale operations related to increased marketing efforts, offset by a 2.5 million gallon decrease in our U.S. wholesale operations.

Results of Operations

Three Months Ended February 28, 2007 Compared to Three Months Ended February 28, 2006.

Parent Company Only Results

The Parent Company currently has no separate operating activities apart from those conducted by ETP and its Operating Partnerships. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and General Partner interests of ETP. The following table summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:

 

    

Three Months Ended

February 28,

         

Six Months Ended

February 28,

       
     2007     2006     Change     2007     2006     Change  

Equity in earnings of affiliates

   $ 174,790     $ 93,948     $ 80,842     $ 234,769     $ 144,881     $ 89,888  

Selling, general and administrative expenses

     (3,609 )     (54,067 )     50,458       (5,308 )     (54,756 )     49,448  

Interest expense

     (24,299 )     (10,555 )     (13,744 )     (51,379 )     (21,299 )     (30,080 )

Loss on extinguishment of debt

     —         (5,060 )     5,060       —         (5,060 )     5,060  

Other expenses, net

     474       169       305       314       270       44  

 

53


Table of Contents

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its ownership of ETP GP and its investment in ETP LLC. The change in equity in earnings of affiliates for the three and six months ended February 28, 2007 compared to the three and six months ended February 28, 2006 is primarily due to an increase of $68.7 million in income allocated to the Incentive Distribution Rights of ETP which ETE owns indirectly through its ownership of ETP GP and ETE’s average ownership percentage of ETP’s limited partner interests increasing from approximately 31% in February 2006 to approximately 46% in February 2007, and the increase in ETP’s income as described below.

Selling, General and Administrative Expenses. The decrease in selling, general and administrative expenses of the Parent Company for the three and six months ended February 28, 2007 compared to the three and six months ended February 28, 2006 is primarily due to the compensation expense of $52.9 million recorded in connection with the issuance of Class B Units by the Parent Company in conjunction with its IPO.

Interest Expense. The Parent Company interest expense increased for the three and six months ended February 28, 2007 compared to 2006 because the Parent Company debt increased from $600.0 million in February 2006 to $1.7 billion in February 2007. Please read “Description of Indebtedness” under “Liquidity and Capital Resources” below for more information on the Parent Company’s indebtedness.

Loss on extinguishment of Debt. The Parent Company expensed $5.1 million in deferred financing costs in the six months ended February 28 2006 in connection with the repayment of a $600.0 million senior secured term loan agreement in conjunction with its IPO. There were no similar transactions during the fiscal 2007 period.

Consolidated Results

 

    

Three Months Ended

February 28,

         

Six Months Ended

February 28,

       
     2007     2006     Change     2007     2006     Change  

Revenues

   $ 2,062,480     $ 2,449,816     $ (387,336 )   $ 3,450,925     $ 4,866,436     $ (1,415,511 )

Cost of sales

     1,485,816       2,008,831       (523,015 )     2,573,159       4,099,458       (1,526,299 )
                                                

Gross margin

     576,664       440,985       135,679       877,766       766,978       110,788  

Operating expenses

     133,809       99,696       34,113       266,190       202,367       63,823  

Selling, general and administrative

     42,589       85,506       (42,917 )     71,359       110,995       (39,636 )

Depreciation and amortization

     48,415       32,070       16,345       85,279       62,037       23,242  
                                                

Consolidated operating income

     351,851       223,713       128,138       454,938       391,579       63,359  

Interest expense

     (65,077 )     (39,096 )     (25,981 )     (133,624 )     (78,239 )     (55,385 )

Equity in earnings (losses) of affiliates

     (514 )     106       (620 )     4,373       (168 )     4,541  

Gain (loss) on disposal of assets

     (3,229 )     662       (3,891 )     (1,285 )     534       (1,819 )

Loss on extinguishment of debt

     —         (5,060 )     5,060       —         (5,060 )     5,060  

Interest and other income, net

     1,652       2,432       (780 )     3,169       3,496       (327 )

Income tax expense

     (2,576 )     (3,289 )     713       (5,449 )     (24,976 )     19,527  

Minority interests

     (134,751 )     (155,033 )     20,282       (143,726 )     (223,130 )     79,404  
                                                

Net income

   $ 147,356     $ 24,435     $ 122,921     $ 178,396     $ 64,036     $ 114,360  
                                                

See the detailed discussion of revenues, costs of sales, margin and operating expense by operating segment below.

Interest Expense. For the three months ended February 28, 2007 compared to the three months ended February 28, 2006, interest expense increased principally due to increased borrowings by the Parent Company as discussed above, a net $11.6 million increase in interest expense related to increased borrowings on ETP’s Senior Notes and Revolving Credit Facility, offset by a decrease of $2.7 million related to interest rate swaps. The increased borrowings were a result of the CCEH and Titan acquisitions. Interest related to debt of Transwestern represents $5.1 million of the increased interest expense during the three months ended February 28, 2007. Propane related interest decreased $2.2 million due primarily to the scheduled debt payments that have occurred between the three month periods.

 

54


Table of Contents

For the six months ended February 28, 2007 compared to the six months ended February 28, 2006, interest expense increased principally due to a net $21.1 million increase in interest expense related to increased borrowings on the Partnership’s Senior Notes and Revolving Credit Facility, and a net increase of $1.0 million related to interest rate swaps. The increased borrowings were a result of the CCEH and Titan acquisitions. Interest related to debt of Transwestern represents $5.1 million of the increased interest expense. Propane related interest decreased $2.2 million due primarily to the scheduled debt payments that have occurred between the six month periods.

Equity in Earnings (Losses) of Affiliates. The increased loss in equity in earnings (losses) of affiliates for the three months ended February 28, 2007 compared to the three months ended February 28, 2006 was due to increased losses from our ownership of a joint venture that was terminated February 28, 2007.

The increase in equity in earnings (losses) of affiliates for the six months ended February 28, 2007 compared to the six months ended February 28, 2006 was due primarily to equity income from our 50% ownership of CCEH for the month of November 2006. We did not have an investment in CCEH last year. We redeemed our investment in CCEH in connection with our Transwestern acquisition.

Gain (Loss) on Disposal of Assets. The loss on disposal of assets reflected in the three months ended February 28, 2007 was principally due to the sale of a compressor station in February 2007.

Income Tax Expense. As a partnership, we are not subject to income taxes. However, certain wholly-owned subsidiaries are corporations that are subject to income taxes. The decreased expense for the three and six months ended February 28, 2007 was attributed principally to higher income from trading gains recognized by a taxable subsidiary during the periods ended February 28, 2006, than was realized by such subsidiary in the current periods. The decrease was partially offset by the Texas margin tax in the period subsequent to January 1, 2007.

Loss on extinguishment of Debt. The Parent Company expensed $5.1 million in deferred financing costs in the six months ended February 28 2006 in connection with the repayment of a $600.0 million senior secured term loan agreement in conjunction with its IPO.

Minority Interests. Minority interest expense primarily represents partnership interests in ETP that the Parent Company does not own. The decrease of $20.2 million and $79.4 million in minority interest for the three and six months ended February 28, 2007 compared to the three and six months ended February 28, 2006 is primarily due to an increase of $28.4 million and $68.7 million in income allocated to the Incentive Distribution Rights of ETP which ETE owns indirectly through its ownership of ETP GP for the three and six months ended February 28, 2007, respectively. The allocation to the Incentive Distribution Rights increased because ETP’s distribution level and number of Limited Partner units outstanding increased significantly from February 28, 2006 to February 28, 2007. In addition ETE’s average ownership of ETP limited partner interests increased from approximately 31% in February 2006 to approximately 46% in February 28, 2007 (see Note 3 to the condensed consolidated financial statements).

Three and Six Month Operating Results by Segment

Midstream

 

    

Three Months Ended

February 28,

   Amount of    

Six Months Ended

February 28,

   Amount of  
     2007    2006    Change     2007    2006    Change  

Revenues

   $ 624,245    $ 1,205,027    $ (580,782 )   $ 1,232,428    $ 2,754,855    $ (1,522,427 )

Cost of sales

     573,712      1,160,557      (586,845 )     1,132,430      2,597,427      (1,464,997 )
                                            

Gross margin

     50,533      44,470      6,063       99,998      157,428      (57,430 )

Operating expenses

     8,906      7,104      1,802       17,793      14,342      3,451  

Selling, general and administrative

     11,014      6,630      4,384       15,403      14,657      746  

Depreciation and amortization

     6,550      4,866      1,684       12,155      9,536      2,619  
                                            

Segment operating income

   $ 24,063    $ 25,870    $ (1,807 )   $ 54,647    $ 118,893    $ (64,246 )
                                            

Gross Margin. For the three months ended February 28, 2007, midstream’s gross margin increased as a result of the following factors:

 

  -  

Increase in processing margin and fee-based revenue from our gathering assets. The increase was due to increased volumes from the completion of our Johnson County plant in the first quarter of 2007, the acquisition of two gathering systems in North Texas during the first fiscal quarter of 2007 and one in the second fiscal quarter of 2007, and favorable processing conditions during the second fiscal quarter of 2007 compared to the same period last year.

 

55


Table of Contents
  -  

Decrease in non-trading margin from our marketing activities. Market conditions, including lower basis differentials between the west and east Texas markets during the fiscal 2007 period, resulted in lower sales volumes conducted by our producer services’ operations. Included in this decrease was a $3.7 million decrease in non-trading mark-to-market gains resulting from market price fluctuations on open derivative positions at February 28, 2007 compared to February 28, 2006.

For the six months ended February 28, 2007, midstream’s gross margin decreased by $57.4 million primarily due to the following factors:

 

  -  

Decrease in net trading revenues. During the fiscal 2006 period we recognized trading gains resulting from market anomalies created by the hurricanes that struck Texas and Louisiana in August and September 2005. There were no significant weather anomalies during the six months ended February 28, 2007.

 

  -  

Decrease in non-trading margin from our marketing activities. Market conditions, including lower basis differentials between the west and east Texas markets, resulted in lower sales volumes conducted by our producer services’ operations. Included in this decrease was a $19.6 million decrease in non-trading mark-to-market gains due to fewer open positions and lower average prices in 2007 as compared to 2006.

 

  -  

Increase in processing margin and fee-based revenue. The increase was due to favorable processing conditions, the completion of our Johnson County plant in the first quarter of 2007, and the acquisition of two gathering systems in North Texas in the first fiscal quarter of 2007 and one in the second fiscal quarter of 2007.

Operating Expenses. Midstream operating expenses increased $1.8 million for the three months ended February 28, 2007 compared to the same period ended February 28, 2006. The increase was primarily driven by increased compressor rentals of $0.8 million, increased pipeline and compressor maintenance of $0.5 million, and increased employee-related costs, such as salaries, incentive compensation and healthcare costs, of $0.5 million.

Midstream operating expenses increased $3.5 million for the six months ended February 28, 2007 compared to the same period ended February 28, 2006. The increase was primarily driven by increased compressor rental expense of $1.6 million, increased pipeline and compressor maintenance of $1.0 million and increased employee-related costs, such as salaries, incentive compensation and healthcare costs, of $0.9 million.

Selling, General and Administrative Expenses. Midstream selling, general and administrative expenses for the three months ended February 28, 2007 increased $4.4 million compared to the three months ended February 28, 2006. The increase was attributable to $4.4 million of legal costs associated with the regulatory inquiries. In addition, effective with the Transwestern acquisition on December 1, 2006, administrative expenses are now allocated to the operating partnerships. This resulted in an allocation of $1.7 million in administrative expenses which previously had not been allocated. There also was a $1.0 million increase in employee-related costs such as salaries, incentive compensation and healthcare costs. These increases were offset by a $0.9 million increase in overhead costs capitalized to capital expansion projects, a $0.5 million decrease of allocated overhead due to more corporate overhead being allocated to the transportation segment, and a $1.3 million decrease in other general and administrative expenses. The allocation of departmental costs is based on factors such as headcount, number of meters, payroll, margin and on-going projects and is intended to fairly present the segment’s operating results.

Midstream general and administrative expenses for the six months ended February 28, 2007 increased $0.8 million compared to the six months ended February 28, 2006. The increase was attributable to $4.4 million of legal costs associated with regulatory inquiries, a $1.7 million allocation of administrative expenses which previously had not been allocated, and increases of $1.2 million in employee-related costs such as salaries, incentive compensation and healthcare costs. The increase was offset by increases of $1.8 million in departmental costs allocated to the transportation and storage operating segment, an increase of $1.3 million in overhead costs capitalized to capital expansion projects, a one-time $0.9 million reimbursement of administrative costs related to the North Side Loop pipeline project from the project partner, and a $2.5 million decrease in other general and administrative expenses.

Depreciation and Amortization. Midstream depreciation and amortization expense increased $1.7 million for the three months ended February 28, 2007 compared to the same three month period in 2006 principally due to additions to property and equipment subsequent to February 28, 2006, the completion of our Johnson County plant in the first fiscal quarter of 2007, and the acquisitions of three gathering systems in the first and second fiscal quarters of 2007.

 

56


Table of Contents

The increase of $2.6 million for the six months ended February 28, 2007 compared to the same six month period in 2006 is principally due to additions to property and equipment subsequent to February 28, 2006, the completion of our Johnson County plant in the first fiscal quarter of 2007, and the acquisitions of three gathering systems in the first and second fiscal quarters of 2007.

Intrastate Transportation and Storage

 

    

Three Months Ended

February 28,

   Amount of    

Six Months Ended

February 28,

   Amount of  
     2007    2006    Change     2007    2006    Change  

Revenues

   $ 1,108,055    $ 1,490,265    $ (382,210 )   $ 1,918,908    $ 3,055,775    $ (1,136,867 )

Cost of sales

     862,617      1,236,485      (373,868 )     1,544,474      2,665,788      (1,121,314 )
                                            

Gross margin

     245,438      253,780      (8,342 )     374,434      389,987      (15,553 )

Operating expenses

     37,341      41,809      (4,468 )     80,139      88,249      (8,110 )

Selling, general and administrative

     13,269      12,752      517       25,371      23,512      1,859  

Depreciation and amortization

     14,083      13,131      952       28,449      24,934      3,515  
                                            

Segment operating income

   $ 180,745    $ 186,088    $ (5,343 )   $ 240,475    $ 253,292    $ (12,817 )
                                            

Gross Margin. For the three months ended February 28, 2007 as compared to three months ended February 28, 2006, intrastate transportation and storage gross margin decreased by $8.3 million, principally due to the following:

 

  -  

Volumes. Although low price differentials between the Waha and Katy market hubs decreased demand for West-to-East transport business, overall volumes on our transportation pipelines were higher during the second fiscal quarter compared to the same period last year due to continued efforts to secure long-term shipper contracts, a colder winter in fiscal 2007 and the completion of Phase I and II of the 42-inch pipeline. We expect our volumes to continue to increase during the next six months of our fiscal year due to the completion of the last phase of our 42-inch pipeline project during March 2007, the completion of various growth projects during the second fiscal quarter of 2007 and the demand for natural gas during the summer months to supply natural gas to electric generating power plants.

 

  -  

Lower natural gas prices. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. Our average natural gas prices for retained fuel decreased from a range of $7.00 to $9.00/MMBtu during the three months ended February 28, 2006 to $6.00 to $7.00/MMBtu during the same period this year resulting in lower revenue.

 

  -  

Margin decrease on HPL. HPL’s margin decreased between the two periods principally due to a $66.9 million decrease in gains from the discontinuation of hedge accounting resulting from our determination that originally forecasted sales of natural gas from the Partnership’s Bammel storage facility were no longer probable to occur by the specified time period, or within an additional two-month time period thereafter. As a result, we recognized previously deferred unrealized gains of approximately $84.7 million during the quarter ended February 28, 2006 and approximately $17.8 million during the same period in 2007. This decrease was offset by an increase in margin related to additional sales of natural gas from our storage facility of 6.4 Bcf due to colder temperatures during the second quarter of 2007 and improved optimization of the pipeline assets.

For the six months ended February 28, 2007 as compared to the six months ended February 28, 2006, intrastate transportation and storage gross margin decreased by $15.5 million, principally due to the following:

 

  -  

Volumes. Although low price differentials between the Waha and Katy market hubs decreased demand for West-to-East transport business, overall volumes on our transportation pipelines were higher during the 2007 fiscal period compared to the same period last year due to continued efforts to secure long-term shipper contracts, a colder winter in fiscal 2007 and the completion of Phase I and II of the 42-inch pipeline. We expect our volumes to continue to increase during the next six months of our fiscal year due to the completion of the last phase of our 42-inch pipeline project in March 2007, the completion of various growth projects during the second fiscal quarter of 2007 and the demand for natural gas during the summer months to supply natural gas to electric generating power plants.

 

57


Table of Contents
  -  

Lower natural gas prices. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. Our average natural gas prices for retained fuel decreased from a range of $7.00 to $12.00/MMBtu during the six months ended February 28, 2006 to $4.00 to $7.00/MMBtu during the same period this year resulting in lower revenue.

 

  -  

Margin decrease on HPL. HPL’s margin decreased $6.4 million between the two periods primarily due to a $66.9 million decrease in gains from the discontinuation of hedge accounting, approximately $18 million in increased margin on gas sold from our Bammel facility and delivered to a customer in September 2005, and lower margins on gas sales due primarily to lower volumes and lower natural gas prices. These decreases were offset by a significant loss on settled derivatives during the fiscal 2006 period.

Operating Expenses. Intrastate transportation and storage operating expenses decreased $4.4 million when comparing the three months ended February 28, 2007 to the corresponding three month period in 2006. The decrease was primarily attributable to a decrease of $8.5 million in fuel consumption and $1.2 million of cost savings as a result of the EMS contract buyout during the three months ended November 30, 2006 offset by increases of $1.7 million in compressor rental expense, $2.0 million in pipeline maintenance, $0.5 million in property taxes, and $1.0 million in other operating expenses.

Intrastate transportation and storage operating expenses decreased $8.1 million when comparing the six months ended February 28, 2007 to the same prior period ended February 28, 2006. The decrease was principally attributable to a decrease of $16.8 million in fuel consumption and a decrease of $2.0 million in compressor maintenance expense. These decreases were offset by increases of $3.7 million in compressor rentals, $2.4 million in property taxes, $2.3 million in pipeline maintenance, and $1.1 million in employee-related costs such as salaries, incentive compensation and healthcare costs.

Selling, General and Administrative Expenses. Intrastate transportation and storage selling, general and administrative expenses increased $0.5 million for the three months ended February 28, 2007 compared to the three months ended February 28, 2006 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is primarily due to the significance of the operations added to the intrastate transportation segment from the various construction projects.

Intrastate transportation and storage general and administrative expenses increased $1.9 million for the six months ended February 28, 2007 compared to the six months ended February 28, 2006 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is due to the increase in employee headcount resulting primarily from the HPL acquisition.

Depreciation and Amortization. Intrastate transportation and storage depreciation and amortization expense increased $1.0 million for the three months ended February 28, 2007 compared to the three months ended February 28, 2006, principally due to additions to property and equipment subsequent to February 28, 2006 offset by $1.1 million of depreciation expense recorded in second fiscal quarter of 2006 for a purchase price allocation related to HPL.

Intrastate transportation and storage depreciation and amortization expense increased $3.5 million from the six months ended February 28, 2006 to the six months ended February 28, 2007. The increase was principally due to additions to property and equipment subsequent to February 28, 2006 offset by $1.1 million of depreciation expense recorded in second fiscal quarter of 2006 for a purchase price allocation related to HPL.

Interstate Transportation

 

    

Three Months Ended

February 28,

   Amount of   

Six Months Ended

February 28,

   Amount of
     2007    2006    Change    2007    2006    Change

Revenues

   $ 58,158    $ —      $ 58,158    $ 58,158    $ —      $ 58,158

Operating expenses

     8,521      —        8,521      8,521      —        8,521

Selling, general and administrative

     5,871      —        5,871      5,871      —        5,871

Depreciation and amortization

     9,654      —        9,654      9,654      —        9,654
                                         

Segment operating income

   $ 34,112    $ —      $ 34,112    $ 34,112    $ —      $ 34,112
                                         

 

58


Table of Contents

The increase in all categories was due to the acquisition of 100% of Transwestern on December 1, 2006.

Retail Propane

 

    

Three Months Ended

February 28,

   Amount of   

Six Months Ended

February 28,

   Amount of
     2007    2006    Change    2007    2006    Change

Retail propane revenues

   $ 499,252    $ 312,227    $ 187,025    $ 765,342    $ 474,420    $ 290,922

Other propane related revenues

     30,303      19,920      10,383      59,452      39,758      19,694

Retail propane cost of sales

     304,634      188,679      115,955      472,253      291,061      181,192

Other propane related cost of sales

     6,730      5,166      1,564      14,461      11,254      3,207
                                         

Gross margin

     218,191      138,302      79,889      338,080      211,863      126,217

Operating expenses

     77,346      49,004      28,342      156,334      96,087      60,247

Selling, general and administrative

     8,594      5,299      3,295      15,046      8,088      6,958

Depreciation and amortization

     17,937      13,744      4,193      34,528      26,954      7,574
                                         

Segment operating income

   $ 114,314    $ 70,255    $ 44,059    $ 132,172    $ 80,734    $ 51,438
                                         

Revenues. Of the total increase in retail propane revenue of $187.0 million between the three months ended February 28, 2007 and 2006, $143.8 million is due to the increase in volumes sold by customer service locations added through the identifiable Titan locations. Revenues also increased in relation to the increased volumes from the blended locations as discussed above, the increase in volumes sold by customer service locations added through other propane acquisitions and, to a lesser extent, higher selling prices over the same period last year. Other propane related revenues increased $10.4 million for the three months ended February 28, 2007 compared to 2006 of which $6.6 million is due to the Titan acquisition in June, 2006 and $3.8 million is due to other propane acquisitions and enhanced fee generating programs in servicing customers.

Of the total increase in retail propane revenue of $290.9 million between the six months ended February 28, 2007 and 2006, $221.9 million is due to the increase in volumes sold by customer service locations added through the identifiable Titan locations. The remaining increase of $69.0 million is due to higher selling prices to retain margin during times of rising fuel costs and from the volumes related to other acquisitions and internal growth. Other propane related revenues increased $19.7 million for the six months ended February 28, 2007 compared to the same six-month period last year primarily due to an increase of $13.2 million from other propane related revenues from the identifiable Titan locations. The remaining increase of $6.5 million in other propane related revenues is due to other propane acquisitions and enhanced fee generating programs in servicing customers.

Costs of Sales. During the three months ended February 28, 2007 compared to the three months ended February 28, 2006, retail propane cost of sales increased by $116.0 million of which $86.1 million is a result of an overall increase in the cost of sales related to the gallons sold by the identifiable customer service locations added through the Titan acquisition. Cost of sales also increased in relation to other increased volumes as described above, and, to a lesser extent, increases in the cost of fuel for the quarter ended February 28, 2007 as compared to the quarter ended February 28, 2006.

During the six months ended February 28, 2007 compared to the six months ended February 28, 2006, retail propane cost of sales increased by $181.2 million of which $137.4 million is a result of an overall increase in the cost of sales related to the gallons sold by the identifiable customer service locations added through the Titan acquisition, and $43.8 million is due to higher cost of fuel and the other increase in volumes sold as described above.

Gross Margin. The overall increase in gross margins for the three and six-month comparable periods ended February 28, 2007 and 2006 is primarily related to the Titan acquisition in June 2006. The propane margin remained strong during the six months ended February 28, 2007 during the periods of warmer weather and higher fuel prices. Optimization of the margins is influenced by market opportunities, independent competitors and concerns for long term retention of customers.

Operating Expenses. During the three and six months ended February 28, 2007, operating expenses increased by $28.3 million and $60.2 million, respectively, compared to the same three and six month periods last year. These increases were due to a $23.7 million and $45.8 million increase for the three and six months ended February 28, 2007, respectively, directly due to the identifiable Titan operations. Other increases in operating expenses relate to higher

 

59


Table of Contents

vehicle fuel costs and other vehicle expenses, and general increases in other operating expenses including safety training costs of the newly acquired employees from the Titan acquisition, enhancements to our IT infrastructure, and other acquisition related costs.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses for the comparable three and six-month periods of February 28, 2007 and 2006 is primarily due to increases from administrative expense allocations, increases in administrative bonuses, salaries and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding and the addition of administrative employees from the Titan acquisition. Effective with the Transwestern acquisition in December 2006, an allocation of administrative expenses is now made to the operating partnerships, which increased the retail propane selling, general and administrative expenses by $2.5 million for the three and six months ended February 28, 2007.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense for the three and six months ended February 28, 2007 as compared to 2006 is due primarily to the acquisition of Titan on June 1, 2006.

Wholesale Propane

 

    

Three Months Ended

February 28,

   Amount of    

Six Months Ended

February 28,

   Amount of  
     2007    2006    Change     2007    2006    Change  

Revenues

   $ 39,209    $ 32,958    $ 6,251     $ 68,246    $ 56,899    $ 11,347  

Cost of sales

     35,684      29,426      6,258       63,225      51,711      11,514  
                                            

Gross margin

     3,525      3,532      (7 )     5,021      5,188      (167 )

Operating expenses

     1,295      916      379       1,826      1,603      223  

Selling, general and administrative

     792      568      224       1,282      971      311  

Depreciation and amortization

     191      223      (32 )     368      407      (39 )
                                            

Segment operating income

   $ 1,247    $ 1,825    $ (578 )   $</