UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
For the Quarterly Period Ended November 30, 2006
OR
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)
(state or other jurisdiction or
incorporation or organization)
(I.R.S. Employer
Identification No.)
2828 Woodside Street
Dallas, 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 January 12, 2007, the registrant had units outstanding as follows:
Energy Transfer Equity, L.P.
132,151,601 Common Units
2,521,570 Class B Units
83,148,900 Class C Units
TABLE OF CONTENTS
Energy Transfer Equity, L.P. and Subsidiaries
i
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:
ii
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(unaudited)
November 30,
2006
August 31,
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Marketable securities
Accounts receivable, net of allowance for doubtful accounts
Accounts receivable from related companies
Inventories
Deposits paid to vendors
Exchanges receivable
Price risk management assets
Prepaid expenses and other
Total current assets
PROPERTY, PLANT AND EQUIPMENT, net
ADVANCES TO AND INVESTMENT IN AFFILIATES
GOODWILL
INTANGIBLES AND OTHER LONG-TERM ASSETS, net
Total assets
The accompanying notes are an integral part of these condensed consolidated financial statements.
1
LIABILITIES AND PARTNERS ‘ CAPITAL (DEFICIT)
CURRENT LIABILITIES:
Accounts payable
Accounts payable to related companies
Exchanges payable
Customer advances and deposits
Accrued and other current liabilities
Price risk management liabilities
Current maturities of long-term debt
Total current liabilities
LONG-TERM DEBT, less current maturities
DEFERRED INCOME TAXES
OTHER NON-CURRENT LIABILITIES
MINORITY INTERESTS
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL (DEFICIT):
General Partner
Limited Partners:
Common Unitholders (132,149,653 and 124,360,520 units authorized, issued and outstanding at November 30, 2006 and August 31, 2006, respectively)
Class B Unitholders (2,521,570 units authorized, issued and outstanding at November 30, 2006 and August 31, 2006)
Class C Unitholders (83,148,900 and 0 units authorized, issued and outstanding at November 30, 2006 and August 31, 2006, respectively)
Accumulated other comprehensive income, per accompanying statements
Total partners’ capital (deficit)
Total liabilities and partners’ capital (deficit)
2
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit and unit data)
REVENUES:
Midstream and transportation and storage
Propane and other
Total revenues
COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage
Cost of products sold, propane and other
Operating expenses
Depreciation and amortization
Selling, general and administrative
Total costs and expenses
OPERATING INCOME
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized
Equity in earnings (losses) of affiliates
Gain (loss) on disposal of assets
Interest and other income, net
INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS
Income tax expense
INCOME BEFORE MINORITY INTERESTS
Minority interests
NET INCOME
GENERAL PARTNER’S INTEREST IN NET INCOME
LIMITED PARTNERS’ INTEREST IN NET INCOME
BASIC NET INCOME PER LIMITED PARTNER UNIT
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING
DILUTED NET INCOME PER LIMITED PARTNER UNIT
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING
3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Net income
Other comprehensive income (loss):
Reclassification adjustment for gains and losses on derivative instruments accounted for as cash flow hedges included in net income before taxes of $(4) and $698
Change in value of derivative instruments accounted for as cash flow hedges, before taxes of $530 and $185
Change in value of available-for-sale securities, before taxes of $(2) and $(1)
Change in income tax expense related to items of other comprehensive income
Comprehensive income
Reconciliation of Accumulated Other Comprehensive Income (Loss)
Balance, beginning of period
Current period reclassification to earnings
Current period change
Balance, end of period
Components of Accumulated Other Comprehensive Income (Loss)
Other comprehensive income (loss) related to:
Commodity related derivative hedges, net of taxes of $645 and $185
Interest rate derivative hedges, net of taxes of $(5) and $698
Available-for-sale securities net of taxes of $(3) and $ (1)
4
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (DEFICIT)
For the Three Months Ended November 30, 2006
Balance, August 31, 2006
Unit issuances
Assumption of related company debt (Note 3)
Distribution to partners
Purchase premium on ETP Class G Units (Note 13)
Balance, November 30, 2006
The accompanying notes are an integral part of this condensed consolidated financial statement.
5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired
Working capital settlement on prior year acquisitions
Capital expenditures
Advances to and investment in affiliates (Note 3)
Proceeds from the sale of assets
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings
Principal payments on debt
Net proceeds from issuance of Common Units
Unit distributions
Debt issuance costs
Net cash provided by financing activities
INCREASE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS, beginning of period
CASH AND CASH EQUIVALENTS, end of period
6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands, except per unit data)
The accompanying unaudited condensed consolidated financial statements include the accounts of Energy Transfer Equity, L.P. (the “Partnership”, “ETE” or the “Parent Company”) and ETE’s controlled subsidiaries: 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”), 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 months ended November 30, 2006 and 2005. The comparability of these financial statements is affected by ETP’s Titan acquisition included in the results of operations beginning June 1, 2006, ETP’s purchase of 50% of CCE Holdings, LLC (“CCEH”) (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 November 30, 2006 and for the three months ended November 30, 2006 and 2005, have been prepared in accordance with accounting principles generally accepted in the United States of America 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 accounting principles generally accepted in the United States of America 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 November 30, 2006, and the results of their operations and their cash flows for the three month periods ended November 30, 2006 and 2005. 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.
Certain prior period amounts have been reclassified to conform to the 2006 presentation. These reclassifications have no impact on net income or total partners’ capital.
7
Business Operations
In order to simplify the obligations of the Partnership under the laws of several jurisdictions in which we operate, our activities are conducted through three subsidiary operating partnerships, ETC OLP, a Texas limited partnership engaged in midstream and transportation and storage natural gas operations, HOLP, a Delaware limited partnership engaged in retail and wholesale propane operations, and Titan, a Delaware limited partnership engaged in retail propane operations (collectively the “Operating Partnerships”). The Partnership, the Operating Partnerships, and their subsidiaries are collectively referred to in this report as “we”, “us”, 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 18 for stand-alone financial information apart from that of the consolidated partnership information included herein.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (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 months ended November 30, 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, and general business and medical self-insurance reserves. Actual results could differ from those estimates.
Regulatory Assets and Liabilities
As a result of our acquisition of Transwestern on December 1, 2006, we will be subject to regulation by certain state and federal authorities. Transwestern will become part of our interstate transportation segment and will have accounting policies that conform to FASB Statement No. 71,Accounting for the Effects of Certain Types of Regulation, which will be in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies will allow 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 our 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 Consolidated Balance Sheet and would be included in the Consolidated Statement of Operations for the period in which the discontinuance of regulatory accounting treatment occurs.
8
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 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. 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, but management does not expect SFAS 154 to have a material impact on our consolidated results of operations, cash flows or financial position.
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
9
would use when pricing the asset or liability. 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.
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 year.
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.
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 are convertible into Common Units upon approval by the ETE Common Unitholders. The Partnership has scheduled a special meeting of its unitholders on February 22, 2007 to consider approval of such conversion.
Also on November 1, 2006, the Parent Company acquired additional limited partner interests in ETP (Class G Units, see Note 13) 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 $30,600 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
10
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 the ETP Revolving Credit Facility. In the aggregate, these acquisitions were not material for pro forma disclosure purposes.
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. The member interests acquired represented a 50% ownership in CCEH. CCEH owns, among other pipelines, the Transwestern Pipeline, a 2,500 mile interstate natural gas pipeline. 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”) on December 1, 2006, following which Southern Union owned all of the member interests of CCEH. Following the final step, Transwestern became a new operating subsidiary of ETP. In connection with the December 1 transaction, ETP assumed approximately $520,000 of long-term indebtedness of Transwestern and received cash of approximately $55,000 (of which $48,763 was received prior to November 30, 2006 from CCEH and was recorded as a reduction of our equity investment in CCEH). ETP financed a portion of the purchase price with the proceeds from the issuance of 26,086,957 ETP Class G Units to ETE simultaneous with the closing on November 1, 2006.
During the quarter ended November 30, 2006, HOLP and Titan collectively acquired substantially all of the assets of two propane businesses. The aggregate purchase price for these acquisitions totaled $2,592 which included $2,250 of cash paid, net of cash acquired, and liabilities assumed of $342. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for acquisitions was financed primarily with ETP’s and HOLP’s Senior Revolving Credit Facilities.
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, as discussed below. As a result of the December 1 transaction noted above, the acquisition of 100% of Transwestern will be accounted for under the purchase method of accounting as of 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 13. Pro forma effects of the CCEH acquisition (using the equity method of accounting) are discussed below.
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 these acquisitions occurring during the period ended November 30, 2006:
Accounts receivable
Inventory
Prepaid and other current assets
Property, plant, and equipment
Intangibles and other assets
Goodwill
Total assets acquired
Long-term debt
Total liabilities assumed
Net assets acquired
11
We recorded the following intangible assets in conjunction with these acquisitions:
Customer lists (15 years)
Non-compete agreements (10 years)
Total amortized intangible assets
Trademarks and trade names
Total intangible assets and goodwill
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.
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 effect of the increase in ownership is reflected in the Partnership’s net income for the three months ended November 30, 2006 and is not reflected in the three months ended November 30, 2005. 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 preliminary results of an independent appraisal. We expect to complete the purchase allocation during our second quarter of fiscal year 2007 upon the completion of the independent appraisal. The Titan operations have been included since the date of acquisition, thus the condensed consolidated results of operations for the three months ended November 30, 2006 include the Titan results of operations for the entire period. However, the three months ended November 30, 2005 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 three months ended November 30, 2006 and 2005 are presented as if the CCEH acquisition and related equity and debt issuances of ETE and ETP had been made on September 1, 2005.
Revenues
Limited Partners’ interest in net income
Basic earnings per Limited Partner Unit
Diluted earnings per Limited Partner Unit
The pro forma consolidated results of operations include adjustments to give effect to depreciation of the equity basis difference 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.
We own interests in a number of related businesses that are accounted for using the equity method. In general we use the equity method of accounting in which we have a 20% to 50% ownership and exercise significant influences over, but do not control, the investee’s operating and financial policies.
12
We record our share of net income or loss from these equity investments in Equity in Earnings of Affiliates in our condensed consolidated statement of operations. The balance of our advances to and investments in affiliates at November 30, 2006 consisted primarily of our investment in CCEH of $956,348 and advances to and investments in other equity affiliates of $42,708. Our equity investment in CCEH includes equity earnings since our acquisition on November 1, 2006 of approximately $5,100 and is net of $48,763 in distributions received from CCEH prior to November 30, 2006.
The following table presents summarized financial information of CCEH since the date of our acquisition (November 1, 2006):
For the
One Month EndedNovember 30, 2006
Operating income
Equity earnings
Net Income
Our 50% share of net income
Less - amortization of our investment in excess of net assets allocated to property and equipment for November 30, 2006
Reported equity earnings
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.
The net change in cash due to changes in operating assets and liabilities (net of acquisitions) is comprised as follows:
Reconciliation of net income to net cash provided by (used in) operating activities:
Amortization of finance costs charged to interest
Provision for loss on accounts receivable
Non-cash compensation on unit grants
Undistributed earnings of affiliates, net
Deferred income taxes
(Gain) loss on disposal of assets
Distributions from subsidiary to minority unitholders
Changes in operating assets and liabilities:
Prep aid expenses and other
Intangibles and other long-term assets
Other long-term liabilities
Income taxes payable
Price risk management liabilities, net
Net cash provided by (used in) operating activities
13
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest, net of $4,802 and $ 307 capitalized for November 30, 2006 and 2005, respectively
Cash paid during the period for income taxes
Our 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 midstream and transportation and storage segments was not significant for the three months ended November 30, 2006; 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 months ended November 30, 2006 and 2005 in the midstream and transportation and storage segments.
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.
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 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.
Accounts receivable consisted of the following:
Accounts receivable - midstream and transportation and storage
Accounts receivable - propane
Less – allowance for doubtful accounts
Total, net
14
The activity in the allowance for doubtful accounts for the retail and wholesale propane segments consisted of the following:
Balance, beginning of the period
Accounts receivable written off, net of recoveries
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:
Natural gas, propane and other NGLs
Appliances, parts and fittings and other
Total inventories
Goodwill is associated with acquisitions made for our midstream, transportation and storage, 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 three month period ended November 30, 2006 were as follows:
Purchase accounting adjustments
Goodwill acquired
Sale of operations
The final assessment of asset values related to the Titan acquisition is expected to be completed in the second quarter of fiscal year 2007 upon the completion of the final independent appraisal. There is no guarantee that the preliminary allocation will not change.
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
15
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 periods ended November 30, 2006 and 2005, 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.
Current provision:
Federal
State
Deferred provision:
Total
Total Tax Provision
The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level. The difference between the statutory rate and the effective rate is summarized as follows:
Federal statutory tax rate
State income tax rate net of federal benefit
Earnings not subject to tax at the Partnership level
Effective tax rate
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. The basic and diluted average Limited Partner units outstanding for the three months ended November 30, 2006 have been restated to reflect the 54.41% unit conversion factor to an equivalent number of Common Units effected in February 2006 as a result of ETE’s IPO. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
Basic Net Income per Limited Partner Unit:
Limited partners’ interest in net income
Weighted average limited partner units
Basic net income per limited partner unit
Diluted Net Income per Limited Partner Unit:
Dilutive effect of subsidiary unit grants
Diluted average limited partner units
Diluted net income per limited partner unit
16
The following table summarizes the changes in minority interest liability:
Minority interest in net income of subsidiaries
Distributions and other
Compensation under employee unit awards by subsidiary
Premium on ETE’s purchase of ETP units (see Note 13)
Change in accumulated other comprehensive income allocable to minority interests
Purchase of interest in consolidated subsidiary from ETI (see Note 3)
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 and will accrue from October 23, 2006. 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 provided 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 assumed debt and for liquidity and general Partnership purposes.
17
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 as of November 30, 2006 was $1,926,100 with no amounts outstanding under the Swingline loan option. The total amount available under the Parent Company Revolving Credit Facility as of November 30, 2006 was $23,900. The Parent Company 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 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 6.58% for the amount outstanding on the Parent Company Senior Secured Revolving Credit Facility, 7.37% for the amount outstanding on the Parent Company $150,000 Senior Secured Term Loan Facility and 7.32% on the $1,300,000 Senior Secured Term Loan Series B Facility as of November 30, 2006.
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 in 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 November 30, 2006, there was a balance of $325,254 in revolving credit loans (including $15,254 in Swingline loans) and $19,451 in letters of credit. The weighted average interest rate on the total amount outstanding at November 30, 2006, was 5.871%. The total amount available under the ETP Revolving Credit Agreement as of November 30, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $1,155,295. 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 weighted average interest rate was 6.466% for the amount outstanding at November 30, 2006. 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 November 30, 2006, there was a balance of $45,000 in 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 November 30, 2006. 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 November 30, 2006 was $28,998.
18
Limited Partner Units
Limited partner interests in the Partnership are represented by Common, Class B Units and Class C Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement, as amended. As of November 30, 2006, we had limited partner interests represented by 132,149,653 Common Units, 2,521,570 Class B Units and 83,148,900 Class C 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 three month period ended November 30, 2006 is as follows:
Issuance of Common Units
On November 28, 2006 the Parent Company sold 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. Subsequent to November 30, 2006 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 three month period ended November 30, 2006.
Class C Units
The Class C Units issued and outstanding during the three month period ended November 30, 2006 are as follows:
Issuance of Class C Units to Energy Transfer Investments, L.P.
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).
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. 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.
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 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%.
19
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 month periods ended November 30, 2006 and 2005.
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 three months ended November 30, 2006 and 2005, respectively. ETE advanced the funds to pay the $24,489 contribution, and such resulted in a receivable from affiliates in the Parent Company stand-alone balance sheet at November 30, 2006.
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.
The total amount of distributions the Parent Company declared on December 19, 2006 (all from Available Cash from Operating Surplus) relating to the three months ended November 30, 2006 was as follows. These distributions will be paid on January 19, 2007 to Unitholders of record on January 4, 2007.
Limited Partners -
Total distributions declared
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:
20
On October 16, 2006, ETP paid a quarterly distribution related to the fourth quarter of fiscal year 2006 of $0.75 per ETP 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, the General Partner of ETP, 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 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 three month period ended November 30, 2006 is as follows:
Limited Partner Interests
General Partner Interest
Incentive Distribution Rights
Total distributions received from ETP
On December 19, 2006, ETP declared a per unit cash distribution of $0.7678, or $3.075 per ETP Limited Partner Unit annually (a $0.0178 increase per ETP Limited Partner Unit) for the quarter ended November 30, 2006, which will be paid on January 15, 2007 to ETP Unitholders of record at the close of business on January 4, 2007.
The total amount of ETP distributions declared (all from Available Cash from Operating Surplus) related to the three months ended November 30, 2006 was as follows:
Class E Units
Class G Units
General Partner -
2% Ownership
Based on ETP’s current quarterly distribution of $0.7678 per unit and the number of its Common Units outstanding at November 30, 2006, the Partnership would be entitled to receive a quarterly cash distribution of $103,199 (or $412,795 on an annualized basis), which consists of $3,271 from the indirect ownership of the 2% general partner interest in ETP, $51,880 from the indirect ownership of the incentive distribution rights in ETP, $27,993 from the Common Units of ETP and $20,054 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. As provided in SFAS 123R, the Partnership values the unit awards based on the per unit grant-date market value reduced by the present value of the distributions expected to be paid on the units during the requisite service period. 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 $3,164 and $447 for the three months ended November 30, 2006 and 2005, respectively, related to unit-based compensation plans of ETP.
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., which is wholly owned and 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. There was no compensation expense related to the ETE Long-Term Incentive Plan recorded by the Partnership for the three months ended November 30, 2006 or 2005.
21
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. As of November 30, 2006, other than the Class B Units discussed above, no awards were outstanding under the ETE Long-Term Incentive plan.
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.
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 4.40% for the three months ended November 30, 2006 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 granted during the three months ended November 30, 2006, the grant-date average per unit cash distributions were estimated to be $5.16. Upon vesting, ETP Common Units are issued.
The following table shows the activity of the awards granted for the three months ended November 30, 2006:
Unvested awards as of August 31, 2006
Awards granted November 1, 2006
Awards vested September 1, 2006
Awards vested November 1, 2006
Unvested awards as of November 30, 2006
22
The total expected compensation expense to be recognized related to the unvested employee awards as of November 30, 2006 is $9,802 for the remainder of fiscal year 2007, $5,328 for fiscal year 2008, and $1,806 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 $15 (changed to $25 in October 2006, as discussed 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 3.85% for the three months ended November 30, 2006, 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 months ended November 30, 2006, the grant-date average per unit cash distributions were estimated to be $4.67.
The following table shows the activity of the Director Grants for the three months ended November 30, 2006:
Annual Director’s Grants awarded October 17, 2006
The total expected compensation expense to be recognized related to the unvested Director Awards as of November 30, 2006 is expected to be $126 for the remainder of fiscal year 2007, $57 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. On October 17, 2006, 3,240 Annual Director Grants were awarded.
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 November 30, 2006, there have been no Long-Term Incentive Grants made under the Plan.
Commitments
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.
23
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 will reduce our working capital requirements that were necessary to finance the working gas while in storage and will provide us an opportunity to offer storage to third parties. This agreement goes into effect beginning 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.
Contingencies
Prior to our completion of the Transwestern Pipeline acquisition on December 1, 2006, our pipelines were intrastate and not generally subject to federal regulation. However, our subsidiaries make deliveries and sales to points or other parties, including other interstate pipelines, designated for interstate delivery. As part of industry-wide inquiries into the natural gas market disruptions occurring around the times of the hurricanes of late 2005, we have participated in discussions with, and have provided information to, industry regulators concerning transactions by our subsidiaries during our fiscal 2006 first and second quarters. We believe, after due inquiry, that our transactions complied in all material respects with applicable rules and regulations. These regulatory inquiries have not yet been concluded. While we are unable to predict the final outcome of these inquiries, management believes it is probable that the industry regulators will require a payment in order to conclude the inquiries. Accordingly, management has provided an accrual at November 30, 2006 for our best estimate of the payment amount that will be required to conclude these inquiries in a negotiated settlement process. We do not expect that any expenditures incurred in connection therewith in excess of the accrual provided as of November 30, 2006 will have a material impact on our financial condition, results of operations or liquidity in any future periods.
Litigation
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. Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP and Titan 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.
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.
24
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, and in the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, may have a significant effect on the results of operations for a single period. However, we believe that such matters will not have a material adverse effect on our financial position. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, we accrue the related deductible.
As of November 30, 2006 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.
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.
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 November 30, 2006 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.
25
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 November 30, 2006 and August 31, 2006, an accrual on an undiscounted basis of $4,412 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 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 November 30, 2006 and August 31, 2006 to account for a predecessor’s share of certain environmental liabilities of ETC OLP.
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 $20,221 during the period between the remainder of calendar year 2006 to 2008, as well as operating and maintenance costs of $22,881 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.
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 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 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 $79,227 and $87,806 as of November 30, 2006 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 margins. We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or
26
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 losses of $3,169 and gains of $101,314 for the three months ended November 30, 2006 and 2005, respectively, related to commodity financial instruments that were previously reported in OCI.
We expect gains before minority interests of $64,447 to be reclassified into earnings over the balance of the fiscal year 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.
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, and changes in the fair value of these derivative instruments are recognized in midstream and transportation and storage revenue in the consolidated statements of operations on a net basis. Net gains associated with trading activities for the three months ended November 30, 2006 and 2005 were $2,963, net of unrealized losses of $11,199, and $52,579, net of unrealized gains of $6,414, respectively.
27
The following table details the outstanding commodity-related derivatives as of November 30, 2006 and August 31, 2006, respectively:
November 30, 2006:
Notional
Volume
MMBTU
Fair
Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX
Swing Swaps IFERC
Fixed Swaps/Futures
Forward Physical Contracts
Options
Forward/Swaps - in Gallons
(Trading)
Cash Flow Hedging Derivatives
August 31, 2006:
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.
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 three months ended November 30, 2006 for a gain of $567.
28
We also 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 $20,280 and $8,699 on the consolidated balance sheets as of November 30, 2006 and August 31, 2006, respectively. The swaps were accounted for as cash flow hedges under SFAS 133 and recorded as a component of OCI.
The Parent Company had 10 year interest rate swaps with a notional amount of $300,000 outstanding as of November 30, 2006. 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 $8,473 and $404 as of November 30, 2006 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 November 30, and August 31, 2006 was a liability and asset of $764 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.
We reclassified into earnings gains of $2,713 and losses of $764 for the three months ended November 30, 2006 and 2005, respectively, related to interest rate swaps that were previously reported in OCI. We expect gains of $219 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 before minority interests:
Unrealized gains (losses) recognized in revenues and cost of products sold related to commodity-related derivative activity excluding ineffectiveness
Ineffective portion of derivatives qualifying for hedge accounting
Realized gains (losses) included in revenues and cost of products sold
Unrealized gains (losses) on interest rate swap included in interest expense, excluding ineffectiveness
Realized gains (losses) on interest rate swap included in interest expense
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 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.
29
Related company receivables and payables as of November 30, 2006 and August 31, 2006 relate to activities in the normal course of business and such amounts are immaterial.
As of November 30, 2006 and August 31, 2006, we had advances due from a propane joint venture of $6,232 and $3,775, respectively, which are included in advances to and investments in affiliates on our condensed consolidated balance sheets.
Our natural gas midstream and transportation and storage operations secure compression services from third parties including Energy Transfer Technologies, Ltd. Energy Transfer Group, LLC is the General Partner of Energy Transfer Technologies, Ltd. 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 three months ended November 30, 2006 and 2005, we made payments totaling $250 and $279, respectively, to the ETG Entities for compression services provided to and utilized in our natural gas midstream and transportation and storage operations. As of November 30, 2006 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 November 30, 2006 were nominal.
See Notes 3 and 13 for discussion of other related party transactions with ETP and ETI.
As of November 30, 2006, our financial statements reflect four reportable segments:
ETC OLP:
HOLP and Titan:
HOLP:
Beginning December 1, 2006, with the completion of our acquisition of Transwestern Pipeline, we will have an additional reporting segment for our interstate transportation operations.
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.
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. Certain overhead costs relating to a reportable segment have been allocated for purposes of calculating operating income.
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.
30
The 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.
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).
Investment in affiliates and equity in earnings (losses) of affiliates related to our investment in Mid-Texas is included in our midstream segment and transportation and storage segment. Our investment in CCEH as of November 30, 2006 is included in the “other” segment for the following segment asset disclosure. This 50% ownership in CCEH was redeemed in connection with the December 1, 2006 acquisition of Transwestern Pipeline.
The following table presents the financial information by segment for the following periods:
Volumes: (unaudited)
Midstream
Natural gas MMBtu/d
NGLs bbls/d
Transportation and storage
Natural gas MMBtu/d – transported
Natural gas MMBtu/d – sold
Propane gallons (in thousands)
Retail
Wholesale
Total gallons
31
Revenues:
Eliminations
Retail propane and other propane related
Wholesale propane
Other
Cost of Sales:
Total cost of sales
Depreciation and Amortization:
Total depreciation and amortization
Operating income (loss):
Selling general and administrative expenses not allocated to segments
Total operating income
Other items not allocated by segment:
Interest expense
32
Additions to Property, Plant and Equipment
Including Acquisitions (accrual basis):
Total Assets:
Following are the stand-alone financial statements of the Parent Company as of November 30, 2006 and August 31, 2006 and for the three month periods ended November 30, 2006 and 2005 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:
33
BALANCE SHEET
INTANGIBLES AND OTHER ASSETS, net
Accounts payable to affiliates
Accrued interest
OTHER NONCURRENT LIABILITIES
Limited Partners
Common Unitholders
Class B Unitholders
Class C Unitholders
Accumulated other comprehensive income
34
STATEMENTS OF OPERATIONS
For the Three Months Ended
SELLING, GENERAL AND ADMINISTRATIVE EXPENSE
Equity in earnings of affiliates
Other, net
35
STATEMENTS OF CASH FLOWS
CASH FLOWS FROM OPERATING ACTIVITIES:
Undistributed earnings of affiliates
Change in operating assets and liabilities
Net cash flows provided by operating activities
Cash invested in subsidiaries
Equity offering
Cash distributions to partners
Net cash provided by (used in) financing activities
36
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 $1,250,000 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 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.
In December 2006, we purchased a gathering system in north Texas for $32,000, subject to adjustments as defined in the agreements. 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.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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 financial condition and results of operations of our subsidiaries, 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. Tabular dollar amounts (except per unit data) are in thousands.
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 transportation and natural gas storage operations, 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, 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.
37
The Parent Company’s long-term debt increased significantly during the three months ended November 30, 2006 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 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 12,000 miles of intrastate pipeline in service, with an additional 600 miles of intrastate pipeline under construction. In connection with the acquisition of Transwestern on December 1, 2006, we also own 2,500 miles of interstate pipelines. The operating results for Transwestern will be included in our results on a consolidated basis beginning December 1, 2006 and reported as a separate operating segment (interstate transportation).
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 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 15 in the accompanying condensed consolidated financial statements.
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.
38
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.
Amounts discussed below reflect 100% of the results of MP Energy Partnership. MP Energy Partnership is a Canadian general partnership in which HOLP owns a 60% interest.
Trends and Outlook
We believe our 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 our acquired Titan operations. Additionally, on December 1, 2006, our acquisition of Transwestern Pipeline became final. We expect this transaction to be immediately accretive to our Common Unitholders.
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”), ETP acquired the member interests in CCEH from GE and certain other investors for $1.0 billion. The member interests acquired represented a 50% ownership in CCEH. CCEH owns, among other pipelines, the Transwestern Pipeline, a 2,500 mile interstate natural gas pipeline. In a second and related transaction, CCEH redeemed ETP’s 50% interest ownership in CCEH in exchange
39
for 100% ownership of Transwestern Pipeline Company, LLC (“Transwestern”) on December 1, 2006, following which Southern Union will own all of the member interests of CCEH. Following the final step, Transwestern became a new operating subsidiary of ETP. In connection with the December 1 transaction, ETP assumed approximately $520.0 million of long-term indebtedness of Transwestern and received cash of approximately $55.0 million (of which approximately $49.0 million was received prior to November 30, 2006). ETP financed a portion of the purchase price with its issuance of approximately 26.1 million Class G Units issued to the Parent Company simultaneous with the closing on November 1, 2006.
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.
North Texas gathering system. In December 2006, we purchased a gathering system in north Texas for $32.0 million, subject to adjustments as defined in the agreements. 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.
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, and the purchase of 50% of CCEH in November 2006 and Titan in June 2006. See Note 3 to our condensed consolidated financial statements for a detailed discussion of our significant acquisitions during the three months ended November 30, 2006. 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, and basis differences between market hubs.
A summary of the effect on the Parent Company’s ownership of ETP limited partner interests through the acquisitions noted above is as follows:
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.
Analysis of Operating Data
Volumes of natural gas sales, NGL sales including propane, and natural gas transported by our midstream, transportation and storage, retail propane, and wholesale propane segments are as follows:
40
Increase
(Decrease)
NGLs Bbls/d
Transportation and Storage
Propane
Propane gallons sold
41
Analysis of Results of Operations
Three Months Ended November 30, 2006 Compared to Three Months Ended November 30, 2005.
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:
Amount of
Change
Selling, general and administrative expenses
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 months ended November 30, 2006 compared to the three months ended November 30, 2005 is primarily due to an increase of $33.8 million in income allocated to the Incentive Distribution Rights of ETP which ETE owns indirectly through its ownership of ETP GP and ETE’s ownership percentage of ETP’s limited partner interests increasing from approximately 33% in November 2005 to approximately 46% in November 2006, offset by the decrease in the ETP segment income as described below.
Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses of the Parent Company for the three months ended November 30, 2006 compared to the three months ended November 30, 2005 is primarily due to additional legal and professional costs and other administrative expenses associated with the Parent Company being a public company for the three months ended November 30, 2006 that were not present in 2005.
Interest Expense. The Parent Company interest expense increased for the three months ended November 30, 2006 compared to 2005 because the Parent Company debt increased from $600.0 million in November 2005 to $1.9 billion in November 2006. Please read “Description of Indebtedness” under “Liquidity and Capital Resources” below for more information on the Parent Company’s indebtedness.
Consolidated Results
Cost of sales
Gross margin
Consolidated operating income
See the detailed discussion of revenues, costs of sales, margin and operating expense by operating segment below.
42
Interest Expense. For the three months ended November 30, 2006 compared to the three months ended November 30, 2005, interest expense increased $29.4 million. The principal factors for this increase are increased borrowings by the Parent Company as discussed above, a net $9.5 million increase in interest expense related to increased borrowings on ETP’s Senior Notes and Revolving Credit Facility, and an increase of $3.6 million related to interest rate swaps. The increased borrowings by ETP were a result of the CCEH and Titan acquisitions.
Equity in Earnings (Losses) of Affiliates. The increase of $5.2 million in equity in earnings (losses) of affiliates for the three months ended November 30, 2006 compared to the three months ended November 30, 2005 is due to our ownership of CCEH for the month of November 2006 which we did not own last year. Our share of CCEH’s net income was $5.1 million for the month of November 2006.
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 of $18.8 million for the three months ended November 30, 2006 is attributed principally to lower income due to gains on financial derivative activity recognized by a taxable subsidiary during the three months ended November 30, 2005 that were not realized by such subsidiary in the current three-month period.
Minority Interests. Minority interest expense primarily represents partnership interests in ETP that the Parent Company does not own. The decrease of $59.1 million in minority interest for the three months ended November 30, 2006 compared to the three months ended November 30, 2005 is primarily due to an increase of $33.8 million in income allocated to the Incentive Distribution Rights of ETP which ETE owns indirectly through its ownership of ETP GP. The allocation to the Incentive Distribution Rights increased because ETP’s distribution level and number of Limited Partner units outstanding increased significantly from November 30, 2005 to November 30, 2006. In addition ETE’s ownership of ETP increased from approximately 31% in November 2005 to approximately 46% in November 30, 2006 (see Note 3 to the condensed consolidated financial statements above).
Net Income. The decrease of $8.6 million in net income between the comparable three month periods of November 30, 2006 and 2005 is a result of many different factors as discussed in greater detail in the discussion of Parent Company Results above and Operating Results by Segment below.
Operating Results by Segment
Midstream Segment
Segment operating income
Gross Margin. For the three months ended November 30, 2006, midstream’s gross margin decreased by $63.5 million primarily due to the following factors:
43
The decrease was offset by an increase in processing margin and fee-based revenue. The increase was due to the favorable processing conditions that we continued to experience in our first fiscal quarter of 2007. Liquid prices remained high while natural gas prices continued to decline or remain relatively low; thereby making processing more attractive. This resulted in higher margins in the current period as compared to the same period last year.
Operating Expenses. Midstream operating expenses increased $1.6 million and was primarily driven by increased compressor rentals of $0.8 million, increased pipeline maintenance of $0.4 million and increased employee-related costs such as salaries, incentive compensation and healthcare costs of $0.3 million.
Selling, General and Administrative Expenses. Midstream selling, general and administrative expenses for the three months ended November 30, 2006 decreased $3.6 million compared to the three months ended November 30, 2005. The decrease was attributable to a $0.9 million decrease in employee-related costs such as salaries, incentive compensation and healthcare costs, a one-time $0.9 million reimbursement of administrative costs related to the North Side Loop pipeline project from the project partner, a $0.5 million decrease due to more measurement expense being allocated to the transportation segment this period, and a $1.3 million decrease of allocated overhead due to more corporate overhead being allocated to the transportation segment. The allocation of departmental costs between the midstream and the transportation and storage segments is based on factors such as headcount, number of meters, and on-going projects and is intended to fairly present the segment’s operating results.
Depreciation and Amortization. Midstream depreciation and amortization expense increased $0.6 million for the three months ended November 30, 2006 compared to the same three month period in 2005 principally due to additions to property and equipment subsequent to November 30, 2005.
Transportation and Storage Segment
Gross Margin. For the three months ended November 30, 2006 as compared to three months ended November 30, 2005, transportation and storage gross margin decreased by $7.2 million, principally due to 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 $10.00-$11.00/MMBtu during the first quarter of fiscal 2006 to $5.00-$6.00/MMBtu during the first quarter of fiscal 2007. The decrease was offset by the following:
Operating Expenses. Transportation and storage operating expenses decreased $3.6 million when comparing the three months ended November 30, 2006 to the corresponding three month period in 2005. The decrease was primarily attributable to a decrease of $8.2 million in fuel consumption and a decrease of $2.3 million in operation overhead/electricity. These decreases were offset by a $1.8 million increase in compressor rentals, a $1.9 million increase in ad valorem taxes, a $1.9 million increase in professional fess due to the EMS contract buyout and a $1.0 million increase in employee related costs such as salaries, incentive compensation and healthcare costs.
44
Selling, General and Administrative Expenses. Transportation and storage selling, general and administrative expenses increased $1.3 million for the three months ended November 30, 2006 compared to the three months ended November 30, 2005 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 transportation segment from the various construction projects.
Depreciation and Amortization. Transportation and storage depreciation and amortization expense increased $2.9 million for the three months ended November 30, 2006 compared to the three months ended November 30, 2005, principally due to additions to property and equipment, most notably the North Side Loop pipeline and phase I of the 42” pipeline project.
Retail Propane Segment
Retail propane revenues
Other propane related revenues
Retail propane cost of sales
Other propane related cost of sales
Revenues. Of the total increase in retail propane revenue of $103.9 million between the three months ended November 30, 2006 and 2005, $78.1 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 $9.3 million for the three months ended November 30, 2006 compared to 2005 primarily due to the Titan acquisition in June, 2006.
Costs of Sales. During the three months ended November 30, 2006 compared to the three months ended November 30, 2005, retail propane cost of sales increased by $65.2 million of which $51.3 million is a result of an overall increase in gallons sold by the identifiable customer service locations added through the Titan acquisitions. Cost of sales also increased in relation to the increased volumes as described above, and, to a lesser extent, increases in the cost of fuel for the quarter ended November 30, 2006 as compared to the quarter ended November 30, 2005.
Gross Margin. The overall increase in gross margins for the three months ended November 30, 2006 compared to the three months ended November 30, 2005 is primarily related to the Titan acquisition in June 2006.
Operating Expenses. During the three months ended November 30, 2006, operating expenses increased by $31.9 million compared to the same three month period last year due to a combination of a $21.4 million increase due to the identifiable Titan operations, increases in our employee base from other acquisitions and annual salary increases, higher fuel costs to run our vehicles and other vehicle expenses, and general increases in other operating expenses including safety training costs of the newly acquired employees from the Titan and other acquisitions and other acquisition related costs.
Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses for the comparable three month periods of November 30, 2006 and 2005 is primarily due to 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.
45
Operating Income. For the three months ended November 30, 2006, total operating income increased by $7.4 million compared to the three months ended November 30, 2005, due to the changes in revenues and expenses described above.
Wholesale Propane Segment
Segment operating income (loss)
Revenues. Of the $5.1 million increase in wholesale revenue for the three months ended November 30, 2006 compared to the same three months in 2005, $4.5 million is related to the increase in gallons sold to new customers in our eastern wholesale and Canadian operations and $0.6 million is related to higher selling prices.
Costs of Sales. For the three months ended November 30, 2006 compared to the corresponding three months in 2005, total cost of sales increased by $5.3 million. Of the increase, $1.0 million is due to higher selling prices and $4.3 million is due to the increase in customers in our eastern wholesale operations described above.
Other operating income (loss)
Unallocated selling, general and administrative expenses
Unallocated Selling, General and Administrative Expenses. The selling, general and administrative expenses that relate to the general operations of the Partnership are not allocated to our segments.
INCOME TAXES
As a Partnership we generally are 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 months ended November 30, 2006 and 2005, our non-qualifying income was not expected to, or did not, exceed the statutory limit.
46
The difference between the statutory rate and the effective rate is summarized as follows:
Income tax expense consists of the following current and deferred amounts:
Current income tax expense (benefit):
Deferred income tax expense:
We do not expect our tax payments in any year to differ significantly from our current tax provisions.
LIQUIDITY AND CAPITAL RESOURCES
Parent Company Only
The Parent Company currently has no separate operating activities apart from those conducted by the 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 amount of cash that ETP can distribute to its partners, including the Parent Company, each quarter is based on earnings from ETP’s business activities and the amount of available cash, as discussed below.
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 currently expects to fund its short-term needs for such items with its distributions from ETP.
On November 1, 2006, ETP issued approximately 26.1 million of its Class G Units to the Parent Company for $1.2 billion, at a price of $46.00 per unit based upon a market discount from the closing price of ETP’s Common Units on October 31, 2006. The ETP Class G Units were issued to the Parent Company pursuant to a customary agreement, and the Parent Company has been granted registration rights. ETP used the proceeds of $1.2 billion in order to fund a portion of the Transwestern Pipeline acquisition and to repay indebtedness ETP incurred in connection with the Titan acquisition as discussed above. The terms of the Class G Units are substantially similar to those of ETP’s Common Units.
On November 1, 2006, the Parent Company entered into a six year $1.3 billion Senior Secured Term Loan Facility with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National 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 transaction with ETI discussed below and for liquidity and general Partnership purposes.
In a separate but related transaction, on November 1, 2006, ETE acquired from ETI the remaining 50% ownership of Class B limited partner interests in ETP GP, which have the right to distributions of general partner Incentive Distributions Rights (“IDRs”) of ETP, which resulted in ETE now owning 100% of the IDRs. The acquisition was effected through an exchange of 83,148,900 newly created ETE Class C Units for the ETP GP Class B interests owned by ETI and the assumption of ETI debt of $70.5 million. See Note 3 of our condensed consolidated financial statements for discussion of the accounting for the transaction with ETI.
47
ETP
ETP’s ability to satisfy its obligations and pay distributions to its general and limited partners will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.
ETP’s future capital requirements will generally consist of:
ETP believes that cash generated from the operations of its businesses will be sufficient to meet anticipated maintenance capital expenditures. ETP will initially finance all capital requirements by cash flows from operating activities. To the extent that its future capital requirements exceed cash flows from operating activities:
On October 3, 2006, ETP announced that it 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 its 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 ETP’s Bammel Storage facility. Under the new agreement with CenterPoint, ETP will no longer need to utilize predominately all of the Bammel Storage facility’s working gas capacity for supplying CenterPoint’s winter needs. This will reduce ETP’s working capital requirements that were necessary to finance the working gas while in storage and will provide ETP an opportunity to offer storage to third parties. This agreement goes into effect beginning April 1, 2007.
Cash Flows
Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, including the recently acquired Titan operations, and other factors.
Operating Activities. Cash provided by operating activities during the three months ended November 30, 2006, was $85.9 million as compared to cash used in operating activities of $35.1 million for the three months ended November 30, 2005. The net cash provided by operations for the three months ended November 30, 2006 consisted of net income of $31.0 million, non-cash charges of ($32.8) million, principally minority interests and depreciation and amortization, cash from changes in operating assets and liabilities of $87.7 million which increased components of working capital. Various components of operating assets and liabilities changed significantly from the prior period due to factors such as the variance in the timing of accounts receivable collections, payments on accounts
48
payable, and the timing of the purchase and sale of inventories related to the propane and transportation and storage operations. Accounts receivable and accounts payable both decreased during the three months ended November 30, 2006 due primarily to decreases in the volumes and prices in the midstream and transportation and storage operating segment.
Investing Activities. Cash used in investing activities during the three months ended November 30, 2006 of $1.2 billion is comprised primarily of cash paid for our investment in CCEH of $1.0 billion (net of the receipt of $49.0 million from CCEH as per the terms of our acquisition agreement), other acquisitions of $32.8 million and $237.1 million invested for maintenance and growth capital expenditures needed to sustain operations.
Financing Activities. Cash provided by financing activities during the three months ended November 30, 2006 was $1.4 billion. We received $213.5 million in proceeds from the sale of Common Units. We had a net increase in our debt level of $1.2 billion of which $1.0 billion was used to fund the purchase of the member interests of CCEH. We paid $20.9 million debt issue costs related to debt issuance during the three months ended November 30, 2006. During the three months ended November 30, 2006, we paid distributions of $39.9 million to our partners.
Financing and Sources of Liquidity
Description of Indebtedness
Our indebtedness as of November 30, 2006 consists of the Parent Company’s Senior Secured Credit Agreement which includes a $1.3 billion Senior Secured Term Loan Facility available through February 8, 2012, a $500.0 million Senior Secured Revolving Credit Facility available through February 8, 2011, and a $150.0 million Senior Secured Term Loan Facility due February 8, 2012. ETP has $750.0 million in principal amount of 5.95% Senior Notes due 2015, $400.0 million in principal amount of 5.65% Senior Notes due 2012, $400.0 million in principal amount of 6.125% Senior Notes due 2017, $400.0 million in principal amount of 6.625% Senior Notes due 2036 and a Revolving Credit Facility that allows for borrowings of up to $1.5 billion available through June 29, 2011. We also currently maintain separate credit facilities for HOLP. The terms of our indebtedness and our Operating Partnerships are described in more detail in our Annual Report on Form 10-K for fiscal 2006 filed with the Securities and Exchange Commission on November 29, 2006.
Parent Company Indebtedness
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 $1.3 billion 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 transaction with ETI discussed above and for liquidity and general Partnership purposes.
The Parent Company Credit Agreement also includes a $500.0 million 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 $10.0 million and a daily rate based on LIBOR. The Parent Company First Amendment to Amended and Restated Credit Agreement also has a $150.0 million Senior Secured Term Loan Facility due February 8, 2012.
The total outstanding amount borrowed under the Parent Company Credit Agreement as of November 30, 2006 was $1.9 billion with no amounts outstanding under the Swingline loan option. The total amount available under the Parent Company Revolving Credit Facility as of November 30, 2006 was $23.9 million. The Parent Company 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 $100.0 million.
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 $150.0 million Senior Secured Term Loan Facility, and the $1.3 billion Senior Secured Term Loan 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 6.73% for the amount outstanding on the Parent Company Senior Secured Revolving Credit Facility, 7.37% for the amount outstanding on the Parent Company $150.0 million Senior Secured Term Loan Facility and 7.32% on the $1.3 billion Senior Secured Term Loan Facility as of November 30, 2006.
49
The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets the Parent Company and its subsidiaries including its ownership of 36.4 million ETP Common Units, 26.1 million 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 in ETP GP.
ETP Facilities
ETP has a $1.5 billion 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 $75.0 million at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on ETP’s credit rating with a maximum fee of 0.175%. As of November 30, 2006, there was a balance of $325.3 million in revolving credit loans (including $15.3 million in Swingline loans) and $19.5 million in letters of credit. The weighted average interest rate on the total amount outstanding at November 30, 2006, was 5.871%. The total amount available under the ETP Revolving Credit Agreement as of November 30, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $1.2 billion. 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.
On October 18, 2006 we paid and retired a $250.0 million unsecured Revolving Credit Facility which matured under its terms on December 1, 2006. Amounts borrowed under this facility bore interest at a rate based on either a Eurodollar rate or a base rate. The maximum commitment fee payable on the unused portion of the facility was 0.25%. The $250.0 million Revolving Credit Facility was fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP.
HOLP Facilities
A $75.0 million Senior Revolving Facility (“the Facility”) is available through June 30, 2011. The Facility has a swingline loan option with a maximum borrowing of $10.0 million at a prime rate. Amounts borrowed under the Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.466% for the amount outstanding at November 30, 2006. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined, 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 Facility. As of November 30, 2006, there was a balance of $45.0 million in revolving credit loans. A Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the Facility. There were outstanding Letters of Credit of $1.0 million at November 30, 2006. The sum of the loans made under the Facility plus the Letter of Credit Exposure and the aggregate amount of all swingline loans cannot exceed the $75.0 maximum amount of the Facility. The amount available under the Facility at November 30, 2006 was $29.0 million.
Cash Distributions
Cash Distributions Received by the Parent Company
Currently, the Parent Company’s only cash-generating assets are its direct and indirect partnership interests in ETP. These ETP interests consist of all of ETP’s 2% general partner interest, ETP’s incentive distribution rights and ETP Common and Class G Units held by the Parent Company.
The total amount of distributions the Parent Company received from ETP relating to its limited partner interests, general partner interest and Incentive Distribution Rights of ETP during the three months ended November 30, 2006 and 2005 were $27.3 million, $2.6 million and $20.0 million, respectively.
On December 19, 2006, ETP declared a per unit cash distribution of $0.7678 for the quarter ended November 30, 2006, which will be paid on January 15, 2007 to ETP Unitholders of record at the close of business on January 4, 2007. ETE will receive distributions on January 15, 2007 from ETP relating to its limited partner interests, general partner interest and Incentive Distribution Rights of ETP of $48.0, million $3.3 million and $51.9 million, respectively.
50
Cash Distributions Paid by the Parent Company
The total amount of distributions the Parent Company declared on December 19, 2006 (all from Available Cash from Operating Surplus) relating to the three months ended November 30, 2006 relating to its Common Units, Class B Units, Class C Units and General Partner was $44.9 million, $0.9 million, $28.3 million, and $0.2 million, respectively.
See Note 2 to our condensed consolidated financial statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended August 31, 2006, in addition to the interim unaudited condensed consolidated financial statements, accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K.
The following table provides a summary of our commodity-related price risk management assets and liabilities at November 30, 2006:
Mark to Mark et Derivatives
Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or
51
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.
Sensitivity Analysis
The table below summarizes our commodity-related financial derivative instruments and fair values as of November 30, 2006. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.
Non-Trading Derivatives
Propane Forwards/Swaps (in Gallons)
Trading Derivatives
Basic Swaps IFERC/NYMEX
The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10 percent change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in our consolidated results of operations or in accumulated other comprehensive income. In the event of an actual 10 percent change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10 percent due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps).
We entered into forward starting interest swaps with a notional value of $400.0 million during the three months ended August 31, 2006. The fair value of the swaps was recorded as a liability of $21.0 million and $8.7 million on the consolidated balance sheets as of November 30, 2006 and August 31, 2006. A hypothetical change of 1% on the underlying interest rate would have an effect of $32.3 million on the value of the swap as of November 30, 2006.
In connection with the Titan acquisition, we assumed a three year LIBOR interest rate swap with a notional amount of $125.0 million. The fair value of this swap as of November 30, and August 31, 2006 was a liability and asset of $0.8 million and $0.5 million, respectively, and was recorded as a component of price risk management assets and liabilities in the consolidated balance sheet. A hypothetical change of 1% on the underlying interest rate would have an effect of $2.7 million on the value of the swap as of November 30, 2006.
The Parent Company had 10 year interest rate swaps with a notional amount of $300.0 million outstanding as of November 30, 2006. The swaps had a net fair value of a liability of $8.5 million and $0.4 million as of November 30, 2006 and August 31, 2006, respectively, which was recorded as a component of price risk management assets and liabilities on the condensed consolidated balance sheets. A hypothetical change of 100 basis
52
points on the underlying interest rates of the interest rate swaps outstanding at November 30, 2006 would have an effect of $23.1 million on the value of the swaps.
We also have long-term debt instruments which are typically issued at fixed interest rates. Prior to or when these debt obligations mature, we may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.
ITEM 4. CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the participation of the Partnership’s management, including the President and Chief Financial Officer of its General Partner, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a–15(e) and 15d–15(e) of the Securities Exchange Act of 1934, as amended) as of November 30, 2006. The Partnership’s management, including the President and Chief Financial Officer, does not expect that its disclosure controls and procedures or its internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The inherent limitations in all control systems include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Based upon the evaluation, our management, including the President and Chief Financial Officer of ETE’s general partner, concluded that our disclosure controls and procedures are adequate and effective at November 30, 2006 to ensure that information required to be disclosed by us in our periodic filings under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
There have been no changes in the Partnership’s internal controls over financial reporting (as defined in Rule 13(a)–15 or Rule 15d–15(f) of the Exchange Act) during the three months ended November 30, 2006, that have materially affected, or are reasonably likely to materially affect, its internal controls over financial reporting except as relates to the Titan acquisition.
We continue to evaluate Titan’s business and are making various changes to its operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over the operations of Titan. We expect that this effort will continue into future fiscal quarters of 2007 due to the magnitude of the business.
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Not applicable.
ITEM 1A. RISK FACTORS
As of November 30, 2006, there had been no significant change in our risk factors from those discussed in our Form 10-K for the year ended August 31, 2006, except as follows. The acquisition of Transwestern and operations in the interstate transportation business results in additional risk factors, including the following:
The pipeline businesses are subject to competition.
The interstate pipeline business of Transwestern competes with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to our customers and end-users, including electricity, coal and fuel oils. The primary competitive
53
factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the demand for natural gas in the areas served by Transwestern.
The success of the pipelines depends on the continued development of additional natural gas reserves in the vicinity of our facilities and our ability to access additional reserves to offset the natural decline from existing wells connected to our systems.
The amount of revenue generated by Transwestern depends substantially upon the volume of natural gas transported. As the reserves available through the supply basins connected to Transwestern’s systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission. Investments by third parties in the development of new natural gas reserves connected to Transwestern’s facilities depend on many factors beyond Transwestern’s control.
The inability to continue to access Tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.
Transwestern’s ability to operate its pipeline system on certain Tribal lands (lands held in trust by the United States for the benefit of a Native American Tribe) will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those Tribal lands. Securing additional rights-of-way is also critical to Transwestern’s ability to pursue expansion projects including Transwestern’s proposed expansion of its San Juan lateral in New Mexico. We cannot assure that Transwestern will be able to acquire new rights-of-way on Tribal lands or maintain access to existing rights-of-way upon the expiration of the current grants. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.
Transwestern is subject to FERC rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating the pipeline.
Rate-making policies by FERC could affect Transwestern’s ability to establish rates, or to charge rates that would cover future increases in its costs, or even to continue to collect rates that cover current costs. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. 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 capacity and transportation facilities. Any successful complaint or protest against Transwestern’s rates could reduce our revenues associated with providing transmission services. We cannot assure you that we will be able to recover all of Transwestern’s costs through existing or future rates.
Transwestern is subject to regulation by FERC in addition to FERC rules and regulations related to the rates it can charge for its services.
FERC’s regulatory authority also extends to:
FERC action in any of these areas or modifications of its current regulations can impair Transwestern’s ability to compete for business, the costs it incurs in its operations, the construction of new facilities or its ability to recover the full cost of operating its pipeline. For example, the development of uniform interstate gas quality standards by FERC could create two distinct markets for natural gas—an interstate market subject to uniform minimum quality
54
standards and an intrastate market with no uniform minimum quality standards. Such a bifurcation of markets could make it difficult for our pipelines to compete in both markets or to attract certain gas supplies away from the intrastate market. The time FERC takes to approve the construction of new facilities could raise the costs of our projects to the point where they are no longer economic.
FERC has authority to review pipeline contracts. If FERC determines that a term of any such contract deviates in a material manner from a pipeline’s tariff, FERC typically will order the pipeline to remove the term from the contract and execute and refile a new contract with FERC or, alternatively, to amend its tariff to include the deviating term, thereby offering it to all shippers. If FERC audits a pipeline’s contracts and finds deviations that appear to be unduly discriminatory, FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.
Should Transwestern fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the recently enacted Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1,000,000 per day for each violation.
Finally, we cannot give any assurance regarding the likely future regulations under which we will operate Transwestern or the effect such regulation could have on our business, financial condition, and results of operations.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Reference is made to the Parent Company’s Current Report on Form 8-K dated November 27, 2006.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
ITEM 5. OTHER INFORMATION
ITEM 6. EXHIBITS
(a) Exhibits
The exhibits listed on the following Exhibit Index are filed as part of this Report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.
With File Number
(Form) (Period Ending or Date)
55
56
57
58
59
60
61
62
63
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
/s/ John W. McReynolds
President and Chief Financial Officer
(duly authorized to sign on behalf of the registrant)
64