Exhibit 99.2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Members
Energy Transfer Partners, L.L.C.
We have audited the accompanying consolidated balance sheet of Energy Transfer Partners, L.L.C. (a Delaware limited liability company and wholly-owned subsidiary of Energy Transfer Equity, L.P.) and subsidiaries as of December 31, 2008. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.
In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Energy Transfer Partners, L.L.C. and subsidiaries as of December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
| /s/ GRANT THORNTON LLP |
| Dallas, Texas |
| February 27, 2009 |
ENERGY TRANSFER PARTNERS, L.L.C. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
| December 31, 2008 | |||
| ASSETS | |||
CURRENT ASSETS: | |||
Cash and cash equivalents | $ | 91,962 | |
Marketable securities | 5,915 | ||
Accounts receivable, net of allowance for doubtful accounts | 591,257 | ||
Accounts receivable from related companies | 17,773 | ||
Inventories | 272,348 | ||
Deposits paid to vendors | 78,237 | ||
Exchanges receivable | 45,209 | ||
Price risk management assets | 5,423 | ||
Prepaid expenses and other | 75,276 | ||
Total current assets | 1,183,400 | ||
PROPERTY, PLANT AND EQUIPMENT, net | 8,296,085 | ||
ADVANCES TO AND INVESTMENT IN AFFILIATES | 10,110 | ||
GOODWILL | 773,282 | ||
INTANGIBLES AND OTHER LONG-TERM ASSETS, net | 394,399 | ||
Total assets | $ | 10,657,276 | |
| LIABILITIES AND MEMBER’S EQUITY | |||
CURRENT LIABILITIES: | |||
Accounts payable | $ | 381,135 | |
Accounts payable to related companies | 34,551 | ||
Exchanges payable | 54,636 | ||
Customer advances and deposits | 106,679 | ||
Accrued wages and benefits | 64,692 | ||
Accrued capital expenditures | 153,230 | ||
Accrued and other current liabilities | 94,066 | ||
Price risk management liabilities | 94,978 | ||
Interest payable | 106,265 | ||
Income taxes payable | 14,538 | ||
Deferred income taxes | 589 | ||
Current maturities of long-term debt | 45,232 | ||
Total current liabilities | 1,150,591 | ||
LONG-TERM DEBT, less current maturities | 5,618,715 | ||
DEFERRED INCOME TAXES | 100,597 | ||
MINORITY INTERESTS AND OTHER NON-CURRENT LIABILITIES | 3,787,357 | ||
COMMITMENTS AND CONTINGENCIES | |||
| 10,657,260 | |||
MEMBER’S EQUITY | 16 | ||
Total liabilities and member’s equity | $ | 10,657,276 | |
The accompanying notes are an integral part of this consolidated balance sheet.
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ENERGY TRANSFER PARTNERS, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2008
(Tabular dollar amounts in thousands)
| 1. | OPERATIONS AND ORGANIZATION: |
Energy Transfer Partners, L.L.C. (“ETP LLC” or “the Company”), a Delaware limited liability company, is the General Partner of Energy Transfer Partners GP, L.P. (“ETP GP”), a Delaware limited partnership formed in August 2000, with a 0.01% general partner interest. ETP GP is the General Partner and owns the 2% general partner interests of Energy Transfer Partners, L.P. (“ETP”).
Energy Transfer Equity, L.P. (“ETE”), is the 100% owner of ETP LLC and also owns 100% of ETP GP.
Balance Sheet Presentation
The accompanying consolidated balance sheet of ETP LLC and subsidiaries presented herein as of December 31, 2008 has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We consolidate all majority-owned and controlled subsidiaries, including ETP and its subsidiaries, La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”), Heritage Operating, L.P. (“HOLP”), Heritage Holdings, Inc. (“HHI”), Titan Energy Partners, L.P. (“Titan”) and Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”), collectively, the “Operating Partnerships”. We present a minority interest liability for all partially-owned consolidated subsidiaries. All significant intercompany accounts are eliminated in consolidation.
We also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other form of entity. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.
In November 2007, ETP changed its fiscal year end to the calendar year. Thus, ETP’s, and our, new fiscal year began on January 1, 2008. ETP subsequently filed audited financial statements for the four-month transition period on Form 8-K on March 19, 2008.
Business Operations
In order to simplify the obligations of ETP under the laws of several jurisdictions in which we conduct business, our activities are primarily conducted through our Operating Partnerships, as follows:
| • | ETC OLP—a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations; |
| • | ET Interstate—the parent company of Transwestern and ETC MEP, all of which are Delaware limited liability companies engaged in interstate transportation of natural gas; |
| • | ETC Fayetteville Express Pipeline, LLC (“ETC FEP”), a Delaware limited liability company engaged in interstate transportation of natural gas; |
| • | HOLP—a Delaware limited partnership primarily engaged in retail propane operations; and |
| • | Titan—a Delaware limited partnership engaged in retail propane operations. |
The Company, ETP GP, ETP, the Operating Partnerships, and their subsidiaries are collectively referred to in this report as “we”, “us”, “our”, “ETP LLC”, or the “Company.”
ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and natural gas liquids (“NGLs”) in the states of Texas, Louisiana, Arizona, New Mexico, Utah and Colorado.
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The midstream operations focus on the gathering, compression, treating, blending, and processing of natural gas, primarily on or through the Southeast Texas System and North Texas System, and marketing activities.
The intrastate transportation and storage operations focus on transporting natural gas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System.
The interstate transportation operations principally focus on the natural gas transportation activities of Transwestern. Transwestern is a major natural gas transporter to the California border and delivers natural gas from the east end of its system to Texas intrastate and Midwest markets. The Transwestern pipeline interconnects with our existing intrastate pipelines in West Texas. The interstate transportation operations also include the joint venture activities of ETC MEP and ETC FEP.
The retail propane operations sell propane and propane-related products and services. The HOLP and Titan customer base includes residential, commercial, industrial and agricultural customers.
| 2. | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES, NEW ACCOUNTING STANDARDS AND BALANCE SHEET DETAIL: |
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosures of contingent assets and liabilities at the date of the balance sheet.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the assets and liabilities as of December 31, 2008 represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in goodwill impairment test, market value of inventory, estimates related to our unit-based compensation plans, deferred taxes, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Regulatory Accounting
Regulatory Assets and Liabilities—Transwestern is subject to regulation by certain state and federal authorities, is part of our interstate transportation segment and has accounting policies that conform to Statement of Financial Accounting Standards No. 71 (As Amended),Accounting for the Effects of Certain Types of Regulation (“SFAS 71”), which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
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Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation (“FDIC”) insurance limit.
Marketable Securities
Marketable securities are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at fair value.
Accounts Receivable
ETC OLP deals with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master set off agreement). Management reviews midstream and intrastate transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and intrastate transportation and storage operations. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Management believes that the occurrence of bad debt in ETC OLP’s accounts receivable was not significant at December 31, 2008; therefore, an allowance for doubtful accounts for the midstream and intrastate transportation and storage operations was not deemed necessary.
ETP’s interstate transportation operations have a concentration of customers in the electric and gas utility industries as well as natural gas producers. This concentration of customers may impact ETP’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral. Transwestern sought additional assurances from customers due to credit concerns, and held aggregate prepayments of $0.8 at December 31, 2008, which are recorded in customer advances and deposits in the consolidated balance sheet. Transwestern’s management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Transwestern establishes an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables. Transwestern considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectibility.
ETP’s propane operations grant credit to their customers for the purchase of propane and propane-related products. Included in accounts receivable are primarily trade accounts receivable arising from HOLP’s retail and wholesale propane Titan’s retail propane operations and receivables arising from liquids marketing activities. Accounts receivable for retail and wholesale propane operations are recorded as amounts are billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the propane operations are based on management’s assessment of the realizability of customer accounts, based on the overall creditworthiness of our customers and any specific disputes.
ETP enters 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 consolidated balance sheet.
ETP exchanged a portion of our outstanding accounts receivable from Calpine Energy Services, L.P. for Calpine Corporation (“Calpine”) common stock during the first quarter of 2008 pursuant to a settlement reached with Calpine related to their bankruptcy reorganization. The stock is included in marketable securities on the consolidated balance sheet as of December 31, 2008 at a fair value of $4.8 million.
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Accounts receivable consisted of the following at December 31, 2008:
Midstream and intrastate transportation and storage | $ | 415,507 | ||
Interstate transportation | 29,309 | |||
Propane | 155,191 | |||
Less – allowance for doubtful accounts | (8,750 | ) | ||
Total, net | $ | 591,257 | ||
Inventories
Inventories consist principally of natural gas held in storage valued at the lower of cost or market utilizing the weighted-average cost method. Propane inventories are 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 at December 31, 2008:
Natural gas and NGLs, excluding propane | $ | 184,727 | |
Propane | 63,967 | ||
Appliances, parts and fittings and other | 23,654 | ||
Total inventories | $ | 272,348 | |
The December 31, 2008 inventory balances reflect lower-of-cost-or-market adjustments of $69.5 million for natural gas inventory and $4.4 million for propane inventory, which were recorded in the fourth quarter of 2008.
Exchanges
Exchanges consist of natural gas and NGL delivery imbalances with others. These amounts, which are valued at market prices, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheet. Management believes market value approximates cost.
Natural gas imbalances occur as a result of differences in volumes of gas received and delivered. Transwestern records natural gas imbalance in-kind receivables and payables at the dollar weighted composite average of all current month gas transactions and dollar valued imbalances are recorded at contractual prices.
Property, Plant and Equipment
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or Federal Energy Regulatory Commission (“FERC”) mandated lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs.
We review property, plant and equipment impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
Capitalized interest is included for pipeline construction projects, except for interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of ETP’s revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
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Components and useful lives of property, plant and equipment at December 31, 2008 were as follows:
Land and improvements | $ | 74,731 | ||
Buildings and improvements (10 to 30 years) | 129,714 | |||
Pipelines and equipment (10 to 80 years) | 5,136,357 | |||
Natural gas storage (40 years) | 92,457 | |||
Bulk storage, equipment and facilities (3 to 30 years) | 496,462 | |||
Tanks and other equipment (5 to 30 years) | 578,118 | |||
Vehicles (5 to 10 years) | 193,645 | |||
Right of way (20 to 80 years) | 358,669 | |||
Furniture and fixtures (3 to 10 years) | 28,075 | |||
Linepack | 48,108 | |||
Pad gas | 53,583 | |||
Other (5 to 10 years) | 97,975 | |||
| 7,287,894 | ||||
Less – Accumulated depreciation | (700,826 | ) | ||
| 6,587,068 | ||||
Plus – Construction work-in-process | 1,709,017 | |||
Property, plant and equipment, net | $ | 8,296,085 | ||
Asset Retirement Obligation
We record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, we also recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.
We have determined that we are obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, management is not able to reasonably measure the fair value of the asset retirement obligations as of December 31, 2008 because the settlement dates are indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.
Advances to and Investment in Affiliates
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 for an investment in which we have a 20% to 50% ownership and exercise significant influence over, but do not control, the investee’s operating and financial policies.
We account for our investments in Midcontinent Express Pipeline, LLC and Fayetteville Express Pipeline LLC using the equity method. See Note 3 for a discussion of these joint ventures.
Goodwill
Goodwill is associated with acquisitions made by our Operating Partnerships. Substantially all of the $773.3 million balance in goodwill is expected to be tax deductible. Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. An annual impairment test is performed as of December 31 for subsidiaries in ETP’s interstate operations and as of August 31 for all others. During the three months ended December 31, 2008, we recorded an impairment of the entire goodwill balance of $11.4 million related to the Canyon Gathering System. No other goodwill impairments were recorded for the year ended December 31, 2008.
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Intangibles and Other Long-Term Assets
Intangibles and other long-term assets are stated at cost net of amortization computed on the straight-line method. We eliminate from our balance sheet the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangibles and other long-term assets were as follows at December 31, 2008:
| December 31, 2008 | |||||||
| Gross Carrying Amount | Accumulated Amortization | ||||||
Amortizable intangible assets: | |||||||
Noncompete agreements (5 to 15 years) | $ | 40,301 | $ | (24,374 | ) | ||
Customer lists (3 to 15 years) | 144,337 | (39,730 | ) | ||||
Contract rights (6 to 15 years) | 23,015 | (3,744 | ) | ||||
Other (10 years) | 2,677 | (2,244 | ) | ||||
Total amortizable intangible assets | 210,330 | (70,092 | ) | ||||
Non-amortizable intangible assets—Trademarks | 75,667 | — | |||||
Total intangible assets | 285,997 | (70,092 | ) | ||||
Other long-term assets: | |||||||
Financing costs (3 to 15 years) | 59,108 | (16,586 | ) | ||||
Regulatory assets | 98,560 | (5,941 | ) | ||||
Other | 43,353 | — | |||||
Total intangibles and other long-term assets | $ | 487,018 | $ | (92,619 | ) | ||
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually or more frequently if circumstances dictate. No impairment of intangible assets was required as of December 31, 2008.
Customer Advances and Deposits
Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month and from our propane customers as security or prepayments for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
Operating expenses | $ | 19,655 | |
Litigation, environmental and other contingencies | 21,886 | ||
Taxes other than income taxes | 20,772 | ||
Other | 31,753 | ||
Total accrued and other current liabilities | $ | 94,066 | |
Minority Interest
Minority interest is $3.77 billion, which represents ETP’s book value of its 152,102,471 ETP Common Units outstanding as of December 31, 2008. In January 2009, ETP issued an additional 6,900,000 Common Units at $34.05 per ETP Common Units.
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Fair Value of Financial Instruments
The carrying amounts of accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at December 31, 2008 was $5.10 billion and $5.66 billion, respectively.
We adopted Statement of Financial Accounting Standards No. 157,Fair Value Measurements, (“SFAS 157”) effective January 1, 2008. SFAS 157 provides a definition of fair value, establishes a fair value framework and hierarchy under GAAP and provides for expanded disclosures of fair value measurements. SFAS 157 does not require any new fair value measurements other than those established by other GAAP requirements. As noted below, under “New Accounting Standards,” the effective date of SFAS 157 has been deferred with respect to certain non-financial assets and liabilities.
We have marketable securities, commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheet. In accordance with SFAS 157, we determine the fair value of our financial assets and liabilities subject to fair value measurement by using the highest possible “Level” as defined in SFAS 157. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“OTC”) commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. We consider the valuation of our interest rate derivatives as Level 2 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and discount the future cash flows accordingly, including the effects of our credit risk. We currently do not have any fair value measurements within the scope of SFAS 157 that require the use of significant unobservable inputs and therefore do not have any assets or liabilities considered as Level 3 valuations as defined by SFAS 157.
The following table summarizes the fair value of our financial assets and liabilities as of December 31, 2008, based on inputs used to derive their fair values in accordance with SFAS 157:
| Fair Value Measurements at Reporting Date Using | |||||||||||
Description | Fair Value Total | Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | ||||||||
Assets | |||||||||||
Marketable Securities | $ | 5,915 | $ | 5,915 | $ | — | |||||
Commodity Derivatives | 111,513 | 106,090 | 5,423 | ||||||||
Liabilities | |||||||||||
Commodity Derivatives | (43,336 | ) | — | (43,336 | ) | ||||||
Interest Rate Derivatives | (51,642 | ) | — | (51,642 | ) | ||||||
| $ | 22,450 | $ | 112,005 | $ | (89,555 | ) | |||||
Income Taxes
ETP LLC is a limited liability company. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual members. Net earnings for financial statement purposes may differ significantly from taxable income reportable to members as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
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As a limited liability company we are generally not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the year ended December 31, 2008 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 basis 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.
Our subsidiary partnerships will be considered to have terminated for federal income tax purposes if transfers of units within a 12-month period constitute the sale or exchange of 50% or more of their capital and profit interests. In order to determine whether a sale or exchange of 50% or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including reported transfers of units by our affiliates and sales of units pursuant to trading activity in the public markets; however, the information we are able to obtain is generally not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our capital and profits interests within the prior 12-month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded.
ETE’s partnership status exceeded the 50% threshold on May 7, 2007, and, as a result, we determined that ETE’s partnership status terminated for federal tax income purposes on that date. ETE’s termination also caused ETP to terminate for federal income tax purposes on that date. These terminations did not affect the classification of ETE or ETP as a partnership for federal income tax purposes or otherwise affect the nature or extent of ETE’s “qualifying income” or the “qualifying income” of ETP for federal income tax purposes. These terminations required both ETE and ETP to close their taxable years and make new elections as to various tax matters. In addition, ETP was required to reset the depreciation schedule for its depreciable assets for federal income tax purposes. The resetting of ETP’s depreciation schedule resulted in a deferral of the depreciation deductions allowable in computing the taxable income allocated to the Unitholders of ETP and, consequently, to ETE’s Unitholders. However, elections ETP and ETE made with respect to the amortization of certain intangible assets had the effect of reducing the amount of taxable income that would otherwise be allocated to ETE Unitholders.
Accounting for Derivative Instruments and Hedging Activities
We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. We apply Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) to account for our derivative financial instruments. SFAS 133 requires that all derivatives be measured at fair value on the balance sheet as either an asset or liability. For qualifying hedges, SFAS 133 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 formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
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.
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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. Certain of our interest rate derivatives are accounted for as cash flow hedges. We report the realized gain or loss and ineffectiveness portions of those hedges in earnings.
Unit-Based Compensation
ETP accounts for awards under its equity incentive plans in accordance with Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payment,(“SFAS 123R”). The grant-date fair value is determined based on the market price of ETP Common Units on the grant date, adjusted to reflect the present value of any expected distributions that will not accrue to the employee during the vesting 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 distributions based on the most recently declared distributions as of the grant date.
New Accounting Standards
Statement of Financial Accounting Standards No. 141 (Revised 2007),Business Combinations(“SFAS 141R”). On December 4, 2007, the FASB issued SFAS 141R, which will significantly change the accounting for business combinations. Under SFAS 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition-date fair value with limited exceptions. Statement 141R will change the accounting treatment for certain specific items, including:
| • | Acquisition costs will generally be expensed as incurred; |
| • | Non-controlling interests (currently referred to as “minority interests”) will be valued at fair value at the acquisition date; |
| • | Acquired contingent liabilities will be recorded at fair value at the acquisition date and subsequently measured at either the higher of such amount or the amount determined under existing guidance for non-acquired contingencies; |
| • | In-process research and development will be recorded at fair value as an indefinite-lived intangible asset at the acquisition date; |
| • | Restructuring costs associated with a business combination will generally be expensed subsequent to the acquisition date; and |
| • | Changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally will affect income tax expense. |
SFAS 141R also includes a substantial number of new disclosure requirements. SFAS 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption is prohibited; therefore, SFAS 141R has not been applied to any transactions presented in these consolidated financial statements. Our adoption of SFAS 141R on January 1, 2009 did not have an immediate impact on our consolidated balance sheet.
Statement of Financial Accounting Standards No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of SFAS Statements No. 87, 88, 106 and 132(R), (“SFAS 158”). Issued in September 2006, this statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multi-employer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. We adopted the recognition and disclosure provisions of SFAS 158 on December 1, 2006 in connection with our acquisition of Transwestern, the effect of which was not material. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. The adoption of the measurement provisions of this statement on January 1, 2008 did not have a material impact on our consolidated balance sheet.
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Statement of Financial Accounting Standards No. 159,The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115, (“SFAS 159”). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective; however, the amendment applies to all entities with available-for-sale and trading securities. We did not elect the fair value option provisions upon adoption of SFAS 159 on January 1, 2008.
Statement of Financial Accounting Standards No. 160,Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51 (“SFAS 160”).On December 4, 2007, the FASB issued SFAS 160. SFAS 160 establishes new accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, SFAS 160 requires the recognition of a non-controlling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the non-controlling interest will be included in consolidated net income on the face of the income statement. SFAS 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. Such gain or loss will be measured using the fair value of the non-controlling equity investment on the deconsolidation date. SFAS 160 also includes expanded disclosure requirements regarding the interests of the parent and its non-controlling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. While the adoption of SFAS 160 will not have a significant impact on our consolidated financial position or results of operations, it will result in certain changes to our financial statement presentation, including the change in classification of non-controlling interest (minority interest) from liabilities to member’s equity on the consolidated balance sheet.
Statement of Financial Accounting Standards No. 161,Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133 (“SFAS 161”).Issued in March, 2008, SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities with the intent to provide users of financial statements with an enhanced understanding of (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under FASB Statement No. 133,Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement has the same scope as SFAS 133, and accordingly applies to all entities. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. SFAS 161 only affects disclosure requirements; therefore, our adoption of this statement effective January 1, 2009 did not impact our consolidated balance sheet.
EITF Issue No. 08-6,Equity Method Investment Accounting Considerations (“EITF 08-6”). Ratified by the FASB on November 24, 2008, EITF 08-6 establishes the requirements for initial measurement of an equity method investment, including the accounting for contingent consideration related to the acquisition of an equity method investment. EITF 08-6 also clarifies the accounting for (1) an other-than-temporary impairment of an equity method investment and (2) changes in level of ownership or degree of influence with respect to an equity method investment. EITF 08-6 is effective on a prospective basis for fiscal years beginning after December 15, 2008. We do not expect our adoption of EITF 08-6 on January 1, 2009 to have a material impact on our consolidated balance sheet.
Statement of Financial Accounting Standards Staff Position (“FSP”) SFAS 157-2,Effective Date of FASB Statement No. 157 (“FSP 157-2”). FSP 157-2 defers the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). As allowed under FSP 157-2, we have not applied the provisions of SFAS 157 to our nonfinancial assets and liabilities measured at fair value, which include impaired nonfinancial assets and certain assets and liabilities acquired in business combinations. We are currently evaluating the impact of our adoption of FSP 157-2 effective January 1, 2009 on our consolidated financial statements. Although our adoption of FSP 157-2 on January 1, 2009, may require additional disclosure, we do not expect an impact to our consolidated balance sheet.
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| 3. | SIGNIFICANT ACQUISITIONS AND JOINT VENTURES: |
Joint Ventures
Midcontinent Express Pipeline LLC
In December 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. (“KMP”) for a 50/50 joint development of Midcontinent Express pipeline, an approximately 500-mile interstate natural gas pipeline that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco’s interstate natural gas pipeline in Butler, Alabama, which is currently pending necessary regulatory approvals. In February 2007, MEP, the entity formed to own and operate this pipeline, initiated public review of the project pursuant to the FERC’s National Environmental Policy Act (“NEPA”) pre-filing review process. MEP filed its application with the FERC for a Certificate of Public Convenience and Necessity in October 2007. In June 2008, the FERC issued an order approving this application. Mobilization for construction of this pipeline commenced in September 2008, following FERC approval. The first phase of the pipeline is expected to be in service by the second quarter of 2009 and the second phase of the pipeline is expected to be in service by the third quarter of 2009. In July 2008, MEP completed an open season with respect to a capacity expansion of MEP from the original planned capacity of 1.5 Bcf/d to a total capacity of 1.8 Bcf/d for the main segment of the pipeline from north Texas to a planned interconnect location with the Columbia Gas Transmission Pipeline near Waverly, Louisiana. The additional 300 MMcf/d of capacity was fully subscribed as a result of this open season. The planned expansion of capacity would be effectuated through the installation of additional compression on this segment of the pipeline and is subject to MEP’s filing of an application with, and approval from, the FERC.
ETP Enogex Partners LLC
In September 2008, we entered into an agreement with OGE Energy Corp. (“OGE”) to form a joint venture entity, ETP Enogex Partners LLC (“ETP Enogex Partners”), to which OGE would contribute its Enogex midstream business and we would contribute our 100% equity interest in Transwestern, our 50% equity interest in MEP, the entity formed to own and operate the Midcontinent Express pipeline, and our 100% equity interest in ETC Canyon Pipeline, LLC, which we refer to as ETC Canyon Pipeline, which owns and operates the Canyon Gathering System. Subsequent to entering into this agreement, conditions in the credit markets deteriorated and the parties were not able to obtain financing on favorable terms. On February 12, 2009, ETP and OGE agreed to terminate the agreement to form a joint venture.
Fayetteville Express Pipeline LLC
In October 2008, we entered into an agreement with KMP for a 50/50 joint development of Fayetteville Express pipeline, an approximately 187-mile natural gas pipeline that will originate in Conway County, Arkansas, continue eastward through White County, Arkansas and terminate at an interconnect with Trunkline Gas Company in Quitman County, Mississippi. FEP, the entity formed to own and operate this pipeline, initiated public review of the project pursuant to the FERC’s NEPA pre-filing review process in November 2008. The pipeline is expected to have an initial capacity of 2.0 Bcf/d. Pending necessary regulatory approvals, the pipeline project is expected to be in service by early 2011. FEP has secured binding 10-year commitments for transportation of approximately 1.85 Bcf/d. The new pipeline will interconnect with Natural Gas Pipeline Company of America (“NGPL”) in White County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi, and ANR Pipeline Company in Quitman County, Mississippi. NGPL is operated and partially owned by Knight, Inc. Knight owns the general partner of KMP. Pursuant to our agreement with KMP related to this project, we and KMP are each obligated to fund 50% of the equity necessary to construct the project.
Significant Acquisitions:
During the year ended December 31, 2008, HOLP and Titan collectively acquired substantially all of the assets of 20 propane businesses. The aggregate purchase price for these acquisitions totaled $96.4 million which included $76.2 million of cash paid, net of cash acquired, liabilities assumed of $ 8.2 million, 53,893 Common Units issued valued at $2.2 million and debt forgiveness of $9.8 million. The cash paid for acquisitions was financed primarily with ETP’s and HOLP’s Senior Revolving Credit Facilities. We recorded $15.3 million of goodwill in connection with these acquisitions.
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| 4. | DEBT OBLIGATIONS: |
Our debt obligations consist of the following:
| December 31, 2008 | Maturities | ||||
ETP Senior Notes: | |||||
9.70% Senior Notes, net of discount of $432 | $ | 599,568 | One payment of $600,000 due March 15, 2019. Interest is paid semi-annually. Put option on March 15, 2012. | ||
6.0% Senior Notes, net of discount of $579 | 349,421 | One payment of $350,000 due July 13, 2013. Interest is paid semi-annually. | |||
6.7% Senior Notes, net of discount of $1,672 | 598,328 | One payment of $600,000 due July 2, 2018. Interest is paid semi-annually. | |||
7.5% Senior Notes, net of discount of $5,703 | 544,297 | One payment of $550,000 due July 1, 2038. Interest is paid semi-annually. | |||
6.125% Senior Notes, net of discount of $295 | 399,705 | One payment of $400,000 due February 15, 2017. Interest is paid semi-annually. | |||
6.625% Senior Notes, net of discount of $2,204 | 397,796 | One payment of $400,000 due October 15, 2036. Interest is paid semi-annually. | |||
5.95% Senior Notes, net of discount of $1,530 | 748,470 | One payment of $750,000 due February 1, 2015. Interest is paid semi-annually. | |||
5.65% Senior Notes, net of discount of $231 | 399,769 | One payment of $400,000 due August 1, 2012. Interest is paid semi-annually. | |||
Transwestern Senior Unsecured Notes: | |||||
5.39% Senior Unsecured Notes, including premium of $3,499 | 91,499 | One payment of $88,000 due November 17, 2014. Interest is paid semi-annually. | |||
5.54% Senior Unsecured Notes, net of discount of $4,330 | 120,670 | One payment of $125,000 due November 17, 2016. Interest is paid semi-annually. | |||
5.64% Senior Unsecured Notes | 82,000 | One payment due May 24, 2017. Interest is paid semi-annually. | |||
5.89% Senior Unsecured Notes | 150,000 | One payment due May 24, 2022. Interest is paid semi-annually. | |||
6.16% Senior Unsecured Notes | 75,000 | One payment due May 24, 2037. Interest is paid semi-annually. | |||
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HOLP Senior Secured Notes: | ||||||
8.55% Senior Secured Notes | 36,000 | Annual payments of $12,000 due each June 30 through 2011. Interest is paid semi-annually. | ||||
Medium Term Note Program: | ||||||
7.17% Series A Senior Secured Notes | 2,400 | Annual payments of $2,400 due each November 19 through 2009. Interest is paid semi-annually. | ||||
7.26% Series B Senior Secured Notes | 8,000 | Annual payments of $2,000 due each November 19 through 2012. Interest is paid semi-annually. | ||||
Senior Secured Promissory Notes: | ||||||
8.55% Series B Senior Secured Notes | 9,142 | Annual payments of $4,571 due each August 15 through 2010. Interest is paid quarterly. | ||||
8.59% Series C Senior Secured Notes | 11,500 | Annual payments of $5,750 due each August 15, 2009 and 2010. Interest is paid quarterly. | ||||
8.67% Series D Senior Secured Notes | 45,550 | Annual payments of $12,450 due August 15, 2009, $7,700 due August 15, 2010, $12,450 due August 15, 2011, and $12,950 due August 15, 2012. Interest is paid quarterly. | ||||
8.75% Series E Senior Secured Notes | 7,000 | Annual payments of $1,000 due each August 15, 2009 through 2015. Interest is paid quarterly. | ||||
8.87% Series F Senior Secured Notes | 40,000 | Annual payments of $3,636 due each August 15, 2010 through 2020. Interest is paid quarterly. | ||||
7.89% Series H Senior Secured Notes | 5,818 | Annual payments of $727 due each May 15 through 2016. Interest is paid quarterly. | ||||
7.99% Series I Senior Secured Notes | 16,000 | One payment of $16,000 due May 15, 2013. Interest is paid quarterly. | ||||
Revolving Credit Facilities: | ||||||
ETP Revolving Credit Facility (including Swingline loan option) | 902,000 | Available through July 2012 – see terms below under “ETP Credit Facility”. | ||||
HOLP Fourth Amended and Restated Senior Revolving Credit Facility | 10,000 | Available through June 30, 2011 - see terms below under “HOLP Credit Facility”. | ||||
Other Long-Term Debt: | ||||||
Notes payable on noncompete agreements with interest imputed at rates averaging 7.91% for December 31, 2008 | 11,249 | Due in installments through 2014. | ||||
Other | 2,765 | Due in installments through 2024. | ||||
| 5,663,947 | ||||||
Current maturities | (45,232 | ) | ||||
| $ | 5,618,715 | |||||
Future maturities of long-term debt for each of the next five years and thereafter are as follows:
2009 | 45,232 | ||
2010 | 40,766 | ||
2011 | 44,454 | ||
2012 | 1,324,896 | ||
2013 | 372,412 | ||
Thereafter | 3,836,187 | ||
| $ | 5,663,947 | ||
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ETP Senior Notes
The ETP Senior Notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the ETP Senior Notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP Senior Notes.
The ETP Senior Notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP Senior Notes is not guaranteed by us or any of ETP’s subsidiaries. As a result, the ETP Senior Notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes effectively rank junior to all indebtedness and other liabilities of ETP’s existing and future subsidiaries.
ETP 9.70% Senior Notes
In December 2008, ETP completed a public offering of $600.0 million aggregate principal amount of 9.70% Senior Notes due 2019 (the “ETP 9.70% Senior Notes”). The holders of the ETP 9.70% Senior Notes have the right to require us to repurchase all or a portion of the notes on March 15, 2012 at the principal amount plus any accrued interest as of that date. ETP used the proceeds of approximately $595.7 million (net of bond discounts of $0.4 million and other offering costs of $3.9 million) from the issuance of the ETP 9.70% Senior Notes to repay other indebtedness.
Interest on the ETP 9.70% Senior Notes is payable semiannually on March 15 and September 15 of each year. ETP may redeem some or all of the ETP 9.70% Senior Notes at any time, or from time to time, pursuant to the terms of the indenture.
ETP 2008 Senior Notes
In March 2008, ETP issued a total of $1.50 billion aggregate principal amount of Senior Notes comprised of $350.0 million of 6.00% Senior Notes due 2013, $600.0 million of 6.70% Senior Notes due 2018, and $550.0 million of 7.50% Senior Notes due 2038 (collectively, the “ETP 2008 Senior Notes”). Proceeds of approximately $1.48 billion (net of bond discounts of $8.2 million and other offering costs of $10.8 million) from the issuance of the ETP 2008 Senior Notes to repay borrowings and accrued interest outstanding under our $500.0 million, 364-day term loan credit facility (the “ETP 364-Day Credit Facility”) and to repay a portion of amounts outstanding under the ETP Credit Facility. Interest on the ETP 2008 Senior Notes is payable semiannually on January 1 and July 1 of each year. ETP may redeem some or all of the ETP 2008 Senior Notes at any time, or from time to time, pursuant to the terms of the indenture.
The ETP 364-Day Credit Facility was a single draw term loan used for general corporate purposes, under which we borrowed the entire amount available under this facility on February 12, 2008, with an applicable Eurodollar rate plus 1.000% per annum based on the current rating by the rating agencies or at the Base Rate for a designated period. The indebtedness under the ETP 364-Day Credit Facility was unsecured and not guaranteed by us or any of our subsidiaries.
ETP 2006 Senior Notes
In October 2006, ETP issued a total of $400.0 million of 6.125% Senior Notes due 2017 and $400.0 million of 6.625% Senior Notes due 2036 (collectively, the “ETP 2006 Senior Notes”). Interest on the senior notes due 2017 is payable semi-annually on February 15 and August 15 of each year, beginning February 15, 2007, and interest on the senior notes due 2036 is payable semi-annually on April 15 and October 15 of each year, beginning April 15, 2007.
ETP 2005 Senior Notes
In July 2005, ETP issued a total of $400.0 million of 5.65% Senior Notes due 2012 (the “ETP 5.65% Senior Notes”). Interest on the ETP 5.65% Senior Notes is payable semi-annually on February 1 and August 1 of each year, beginning on February 1, 2006.
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In January 2005, ETP issued a total of $750.0 million of 5.95% Senior Notes due 2015 (the “ETP 5.95% Senior Notes,” and collectively with the ETP 5.65% Senior Notes, the “ETP 2005 Senior Notes”). Interest on the ETP 5.95% Senior Notes is payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2005.
Transwestern Senior Unsecured Notes
Transwestern’s long-term debt consists of $213.0 million remaining principal amount of notes assumed in connection with the Transwestern acquisition and $307.0 million in principal amount of notes issued in May 2007, the proceeds from which were used to repay other indebtedness and for general corporate purposes. No principal payments are required under any of the Transwestern notes prior to their respective maturity dates. The Transwestern notes rank pari passu with Transwestern’s other unsecured debt. The Transwestern notes are prepayable at any time in whole or pro rata in part, subject to a premium or upon a change of control event, as defined.
Transwestern’s credit agreements contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and require certain debt to capitalization ratios.
HOLP Senior Secured Notes
All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes (collectively, the “HOLP Notes”). In addition to the stated interest rate for the HOLP Notes, we are required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. As of December 31, 2008 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.
Revolving Credit Facilities
ETP Credit Facility
The ETP Credit Facility provides for $2.00 billion of revolving credit capacity that is expandable to $3.00 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing capacity, under the Amended and Restated Credit Agreement). The ETP Credit Facility matures on July 20, 2012, unless we elect the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). Amounts borrowed under the ETP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The ETP Credit Facility includes a swingline loan option of which borrowings and aggregate principal amounts shall not exceed the lesser of (i) the aggregate commitments ($2.00 billion unless expanded to $3.00 billion) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment. The aggregate amount of swingline loans in any borrowing shall not be subject to a minimum amount or increment. The indebtedness under the ETP Credit Facility is prepayable at any time at the Company’s option without penalty. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on ETP’s credit rating and the fee is 0.11% based on ETP’s current rating with a maximum fee of 0.125%.
As of December 31, 2008, there was a balance outstanding in the ETP Credit Facility of $902.0 million in revolving credit loans, with no outstanding balance in swingline loans, and approximately $60.0 million in letters of credit. The weighted average interest rate on the total amount outstanding at December 31, 2008, was 2.82%. The total amount available under the ETP Credit Facility, as of December 31, 2008, which is reduced by any letters of credit, was approximately $1.04 billion ($1.27 billion on a pro forma basis after giving effect to the $225.9 million of net proceeds from our equity offering in January 2009). The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of our or ETP’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In connection with entering into the credit agreement for the ETP Credit Facility (July 2007), all guarantees by ETC OLP, Titan and their direct and indirect wholly-owned subsidiaries of the ETP Senior Notes were released and discharged. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt.
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HOLP Credit Facility
HOLP has a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available to HOLP through June 30, 2011, which may be expanded to $150.0 million. The HOLP Credit Facility includes a swingline loan option with a maximum borrowing of $10.0 million at a prime rate. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined, 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 Credit Facility (total book value as of December 31, 2008 of approximately $1.3 billion). At December 31, 2008, there was $10.0 million outstanding on the revolving credit loans. A letter of credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Credit Facility. There were outstanding letters of credit of $1.0 million at December 31, 2008. The sum of the loans made under the HOLP Credit Facility plus the letter of credit exposure and the aggregate amount of all swingline loans cannot exceed the $75.0 million maximum amount of the HOLP Credit Facility. The amount available as of December 31, 2008 was $64.0 million.
Covenants Related to Our Credit Agreements
The agreements related to the ETP Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The agreements and indentures related to the HOLP Notes, the ETP Credit Facility and the HOLP Credit Facility contain customary restrictive covenants applicable to ETP and the Operating Partnerships, including the achievement of various financial and leverage covenants, limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens as described in more detail below.
The credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to certain exceptions) us, ETP and certain of the ETP’s subsidiaries, ability to, among other things:
| • | incur indebtedness; |
| • | grant liens; |
| • | enter into mergers; |
| • | dispose of assets; |
| • | make certain investments; |
| • | make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement); |
| • | engage in business substantially different in nature than the business currently conducted by ETP and its subsidiaries; |
| • | engage in transactions with affiliates; |
| • | enter into restrictive agreements; and |
| • | enter into speculative hedging contracts. |
The credit agreement related to the ETP Credit Facility also contains a financial covenant that provides that on each date ETP makes a distribution, the leverage ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a specified acquisition period, as defined in the ETP Credit Facility.
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The agreements related to the HOLP Notes and the HOLP Credit Facility contain customary restrictive covenants applicable to HOLP, including the maintenance of various financial and leverage covenants and limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens. The financial covenants require HOLP to maintain ratios of Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the agreements related to the HOLP Notes and HOLP Credit Facility) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the agreements related to the HOLP Notes and HOLP Credit Facility) of not less than 2.25 to 1. These debt agreements also provide that HOLP may declare, make, or incur a liability to make restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed the amount of Available Cash (as defined in the agreements related to the HOLP Notes and HOLP Credit Facility) with respect to the immediately preceding quarter (which amount is required to reflect a reserve equal to 50% of the interest to be paid on the HOLP Notes during the last quarter and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the HOLP Notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates), (b) no default or event of default exists before such restricted payments, and (c) the amounts of HOLP’s restricted payment is not disproportionately greater than the payment amount from ETC OLP utilized to fund payment obligations of ETP and ETP GP with respect to ETP’s Common Units.
Failure to comply with the various restrictive and affirmative covenants of our bank credit facilities and the note agreements related to the HOLP Notes could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Partnerships’ ability to incur additional debt and/or our ability to pay distributions. We are required to measure these financial tests and covenants quarterly. We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2008.
| 5. | MEMBER’S EQUITY: |
Member’s Equity
The ETP LLC membership agreement contains specific provisions for the allocation of net earnings and losses to members for purposes of maintaining the partner capital accounts. The Board of the Company may distribute to the Members funds of the Company which the Board reasonably determines are not needed for the payment of existing or foreseeable company obligations and expenditures.
| 6. | UNIT-BASED COMPENSATION PLANS OF ETP: |
ETP has issued equity awards to employees and directors under the following plans:
| • | 2008 Long-Term Incentive Plan.On December 16, 2008, ETP Unitholders approved the ETP 2008 Long-Term Incentive Plan (the “ETP 2008 Incentive Plan”), which provides for awards of options to purchase ETP Common Units, awards of restricted units, awards of phantom units, awards of Common Units, awards of distribution equivalent rights (“DERs”), awards of Common Unit appreciation rights, and other unit-based awards to employees of us, ETP, ETP GP (ETP’s General Partner), a subsidiary or their affiliates, and members of the Company’s board of directors, which we refer to as our board of directors. Up to 5,000,000 ETP Common Units may be granted as awards under the 2008 Incentive Plan, with such amount subject to adjustment as provided for under the terms of the 2008 Incentive Plan. The 2008 Incentive Plan is effective until December 16, 2018 or, if earlier, the time which all available units under the 2008 Incentive Plan have been issued to participants or the time of termination of the plan by our board of directors. As of December 31, 2008, a total of 4,776,655 ETP Common Units remain available to be awarded under the 2008 Incentive Plan. |
| • | 2004 Unit Plan.ETP’s Amended and Restated 2004 Unit Award Plan (the “ETP 2004 Unit Plan”) provides for awards of up to 1,800,000 ETP Common Units and other rights to our employees, officers, and directors. Any awards that are forfeited or which expire for any reason or any units which are not used in the settlement of an award will be available for grant under ETP’s 2004 Unit Plan. As of December 31, 2008, 16,847 ETP Common Units were available for future grants under ETP’s 2004 Unit Plan. |
| • | Restricted Unit Plan.ETP’s Restricted Unit Plan provided rights for certain of our directors and key employees of and our affiliates to acquire up to 292,000 Common Units of ETP. Following the June 23, 2004 approval of the 2004 Unit Plan at the special meeting of the ETP Unitholders, ETP’s Restricted Unit Plan was terminated (except for the obligation to issue Common Units at the time the 16,592 grants previously awarded vest), and no additional grants have been or will be made under ETP’s Restricted Unit Plan. No unvested awards remain under this plan. |
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Employee Grants
Prior to December 2007, substantially all of the awards granted to employees under ETP’s 2004 Unit Plan required the achievement of performance objectives in order for the awards to become vested. The expected life of each unit award subject to the achievement of performance objectives is assumed to be the minimum vesting period under the performance objectives of such unit award. Generally, each award was structured to provide that, if the performance objectives related to such award are achieved, one-third of the units subject to such award will vest each year over a three-year period with 100% of such one-third vesting if the total return for our units for such year is in the top quartile as compared to a peer group of energy-related publicly traded limited partnerships determined by the Compensation Committee, 65% of such one-third vesting if the total return of our units for such year is in the second quartile as compared to such peer group companies, and 25% of such one-third vesting if the total return of our units for such year is in the third quartile as compared to such peer group companies. Total return is defined as the sum of the per unit price appreciation in the market price of our units for the year plus the aggregate per unit cash distributions received for the year. Non-cash compensation expense is recorded for these awards based upon the total awards granted over the required service period that are expected to vest based on the estimated level of achievement of performance objectives. As circumstances change, cumulative adjustments of previously-recognized compensation expense are recorded.
Commencing in December 2007, ETP also granted restricted unit awards to employees that vest over a specified time period, with vesting based on continued employment as of each applicable vesting date without regard to the satisfaction of any performance objectives. Upon vesting, ETP Common Units are issued.
The unit awards under ETP’s 2004 Unit Plan generally require the continued employment of the recipient during the vesting period. The Compensation Committee has in the past and may in the future, but is not required to, accelerate the vesting of unvested unit awards in the event of the termination or retirement of an executive officer.
In October 2008 and December 2008, the Compensation Committee approved the grant of new unit awards under ETP’s 2004 Unit Plan and 2008 Incentive Plans to certain of ETP’s employees, including certain of its executive officers. All of these unit awards provided for vesting over a five-year period at 20% per year, subject to continued employment through each specified vesting date. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders. We refer to these rights as “distribution equivalent rights.”
Prior to the October 2008 and December 2008 grants, units were generally awarded without distribution equivalent rights. For such awards, ETP calculated the grant-date fair value based on the market value of the underlying units, 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 distribution yield at that time.
As of December 31, 2008, unvested employee awards consisted of 150,852 units with three-year performance vesting conditions, 1,205,430 units with five-year service vesting conditions and 8,976 with other vesting conditions. These awards had weighted average grant-date fair values of $43.96 per unit, $35.87 per unit, and $43.48 per units, respectively.
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The total expected non-cash compensation expense to be recognized related to the unvested employee awards as of December 31, 2008 was:
Year Ending December 31: | Three-Year Performance Vesting | Five-Year Service Vesting | Other | Total | ||||
2009 | 1,008 | 18,229 | 33 | 19,270 | ||||
2010 | — | 10,259 | — | 10,259 | ||||
2011 | — | 6,018 | — | 6,018 | ||||
2012 | — | 3,142 | — | 3,142 | ||||
2013 | — | 1,011 | — | 1,011 |
Director Grants
The ETP 2008 Incentive Plan provides for annual grants of ETP Common Units to its non-employee directors equal to $50 thousand divided by the fair market value of ETP’s Common Units as of each anniversary date of December 19, 2008, the date of the adoption of the 2008 Incentive Plan.
Under the ETP 2004 Unit Plan, each director who was not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of us, ETP GP, ETP, or a subsidiary (“Director Participant”), who was elected or appointed to the Board for the first time automatically received, 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”). In addition, each September 1 each Director Participant who was in office on such September 1, automatically received an award of Units equal to $25 thousand divided by the fair market value of a Common Unit on such date rounded to the nearest increment of ten Units (“Annual Director’s Grant”). Each grant of an award to a Director Participant vested 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 became fully vested upon a change in control, as defined by the Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which had not yet vested on the date a Director Participant ceased to be a director vested on such terms as determined by the Compensation Committee.
As of December 31, 2008, a total of 7,310 unvested Director Awards remain outstanding with a weighted average grant-date fair value of $40.72 per unit. The total expected non-cash compensation expense to be recognized related to the unvested ETP Director Awards as of December 31, 2008 was:
Years Ending December 31: | |||
2009 | $ | 122 | |
2010 | 44 | ||
2011 | 10 | ||
Related Party Awards
During 2007, a partnership (McReynolds Energy Partners, L.P.), the general partner of which is owned and controlled by the President of our General Partner, awarded to certain new officers of ETP certain rights related to units of ETE previously issued by ETE to such officer. These rights include the economic benefits of ownership of these ETE units based on a five year vesting schedule whereby the officer will vest in the ETE units at a rate of 20% per year. As these ETE units are conveyed to the recipients of these awards upon vesting from a partnership that is not owned or managed by ETE or ETP, none of the costs related to such awards are paid by ETP or ETE unless this partnership defaults under its obligations pursuant to these unit awards. Based on GAAP covering related party transactions and unit-based compensation arrangements, we are recognizing non-cash compensation expense over the vesting period based on the grant date fair value of the ETE units awarded the ETP employees assuming no forfeitures.
Rights related to 55,000 ETE units vested in December 2007, rights related to 60,000 ETE units vested in March 2008, rights related to 20,000 ETE units vested in June 2008, and rights related to 55,000 ETE units vested in December 2008. In June 2008, rights related to 240,000 ETE units were forfeited due to the resignation of an officer of ETP.
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In July 2008, rights related to 240,000 ETE units were awarded to ETP’s current chief financial officer. In December 2008, rights related to 210,000 ETE units were awarded to ETP’s president and chief operating officer. These awards have similar terms to those discussed above, including vesting over five years at 20% per year. As discussed above, none of the costs related to these awards will be paid by ETP or ETE unless this partnership defaults under its obligations pursuant to these unit awards. As these unit awards are viewed as compensation to these recipients for financial reporting purposes, the Compensation Committee considered and approved these unit awards.
As of December 31, 2008, rights related to 695,000 unvested ETE units remained outstanding. As these units were outstanding prior to these awards, these awards do not represent an increase in the number of outstanding units of either ETP or ETE and are not dilutive to cash distributions per unit with respect to either ETP or ETE. As of December 31, 2008, ETP expects to recognize non-cash compensation expense as follows in future periods related to these awards:
Years Ending December 31: | |||
2009 | $ | 6,395 | |
2010 | 3,663 | ||
2011 | 2,034 | ||
2012 | 847 | ||
2013 | 277 | ||
| 7. | INCOME TAXES: |
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the deferred tax liability were as follows at December 31, 2008:
Property, plant and equipment | $ | 105,032 | ||
Other, net | (3,846 | ) | ||
Total deferred tax liability | $ | 101,186 | ||
| 8. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES: |
Regulatory Matters
On September 29, 2006, Transwestern filed revised tariff sheets under Section 4(e) of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective on November 1, 2006. In April 2007, the FERC approved a Stipulation and Agreement of Settlement (“Stipulation and Agreement”) that resolved the primary components of the rate case. Transwestern’s tariff rates and fuel charges are now final for the period of the settlement. Transwestern is not required to file a new rate case until October 1, 2011.
The Phoenix project, as filed with the FERC on September 15, 2006, includes the construction and operation of approximately 260 miles of 36-inch or larger diameter pipeline extending from Transwestern’s existing mainline in Yavapai County, Arizona to delivery points in the Phoenix, Arizona area and certain looping on Transwestern’s existing San Juan Lateral with approximately 25 miles of 36-inch diameter pipeline. On November 15, 2007, the FERC issued an order granting Transwestern its Certificate of Public Convenience and Necessity (“Order”). Pursuant to the Order, Transwestern filed its initial Implementation Plan on November 14, 2007 and accepted the Order on November 19, 2007. On December 17, 2007, two parties filed requests for rehearing of the Order and on December 20, 2007, one party filed a motion to stay the Order. On February 21, 2008, the FERC reaffirmed its decision in the Order; thus, Transwestern notified customers of the commencement of construction in January 2008. The San Juan Lateral portion of the project was placed in service effective July 2008 and the pipeline to the Phoenix area was completed in February 2009.
Certain regulatory approvals are still pending with respect to the expansion and interim service of MEP.
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Guarantees
On February 29, 2008, MEP entered into a credit agreement that provides for a $1.40 billion senior revolving credit facility (the “MEP Facility”). We have guaranteed 50% of the obligations of MEP under the MEP Facility, with the remaining 50% of MEP Facility obligations guaranteed by KMP. Subject to certain exceptions, our guarantee may be proportionately increased or decreased if our ownership percentage increases or decreases. The MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 0.15%. The MEP Facility also has a swingline loan option with a maximum borrowing of $25.0 million at a prime rate. The sum of the loans, swingline loans and letters of credit may not exceed the maximum amount of revolving credit available under the MEP Facility. The indebtedness under the MEP Facility is prepayable at any time at the option of MEP without penalty. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets. The MEP Facility is syndicated among multiple financial institutions; the Royal Bank of Scotland PLC is the administrative agent. Among the lending banks that make up the syndicate of financial institutions for the MEP Facility, affiliates of Lehman Brothers had committed to approximately $100.0 million of the $1.40 billion facility. As a result of the Lehman Brothers bankruptcy in 2008, the MEP Facility has effectively been reduced by the amount of the Lehman Brothers affiliates’ commitment. However, the MEP Facility is not in default, and the commitments of the other lending banks remain unchanged.
In March 2008, MEP reimbursed ETP a net $63.5 million from the MEP Facility for previous advances ETP made to MEP. As of December 31, 2008, MEP had $837.5 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. Our contingent obligations with respect to our 50% guarantee of MEP’s outstanding borrowings and letters of credit were $418.8 million and $16.7 million, respectively, as of December 31, 2008. The weighted average interest rate on the total amount outstanding as of December 31, 2008 was 3.1271%. The total amount available under the MEP Facility was $429.2 million as of December 31, 2008.
MEP previously had a $197.0 million reimbursement agreement under which MEP could issue letters of credit. This reimbursement agreement expired in 2008 and there are no longer any letters of credit outstanding.
Commitments
In the normal course of our business, we 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 have also entered into several propane purchase and supply commitments which are typically one year agreements with varying terms as to quantities, prices and expiration dates. We also have a long-term purchase contract for approximately 79.0 million gallons of propane per year that contains a two-year cancellation provision and a seven year contract to purchase not less than 90.0 million gallons per year. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.
We have certain non-cancelable leases for property and equipment which require fixed monthly rental payments and expire at various dates through 2020. Future minimum lease commitments for such leases are:
2009 | $ | 21,041 | |
2010 | 19,854 | ||
2011 | 18,644 | ||
2012 | 16,573 | ||
2013 | 14,426 | ||
Thereafter | 224,110 |
We have forward commodity contracts which are expected to be settled by physical delivery. Short-term contracts which expire in less than one year require delivery of up to 488,097 MMBtu/d. Long-term contracts require delivery of up to 15,878 MMBtu/d and extend through July 2018.
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During fiscal year 2007, 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 the agreements, 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.
We have an eight year transportation agreement with TXU Portfolio Management Company, LP (“TXU Shipper”) to transport a minimum of 100,000 MMBtu per year. We also have two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas facilities that are part of the ET Fuel System.
We have signed long-term agreements with several parties committing firm transportation volumes into the East Texas pipeline. Those commitments include an agreement with XTO Energy Inc. (“XTO”) to deliver approximately 200,000 MMBtu/d of natural gas into the pipeline. The term of the XTO agreement began in June 2004 when the pipeline became operational and expires in June 2012.
We also have two new long-term agreements committing firm transportation volumes on certain of our transportation pipelines. The two contracts require an aggregated capacity of approximately 238,000 MMBtu/d of natural gas and extend through 2011.
Titan has a long-term purchase contract with Enterprise to purchase substantially all of Titan’s propane requirements. The contract continues until March 31, 2010 and contains renewal and extension options. The contract contains various service level agreements between the parties.
In connection with the sale of our investment in M-P Energy in October 2007, we executed a seven-year propane purchase agreement for approximately 90.0 million gallons per year at market prices plus a nominal fee.
ETP previously had a percentage guaranty with a financial institution whereby we would be liable for our 50% of any defaulted payments not made by MEP, plus interest. The reimbursable agreement which had a commitment up to $197.0 million expired in September 2008.
Litigation and Contingencies
The Operating Partnerships may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and propane are flammable, combustible gases. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, the Operating Partnerships 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.
FERC/CFTC and Related Matters. On July 26, 2007, the FERC issued to us an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that we violated FERC rules and regulations. The FERC has alleged that we engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from our commodities derivatives positions and from certain of our index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods we violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the Natural Gas Act (“NGA”). We allegedly violated this rule by artificially suppressing prices that were included in the PlattsInside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. Additionally, the FERC has alleged that we manipulated daily prices at the Waha and Permian Hubs in west Texas on two dates. Our Oasis pipeline transports interstate natural gas pursuant to Natural Gas Policy Act (“NGPA”) Section 311 authority and is subject to the FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline include claims that the Oasis pipeline violated NGPA regulations from January 26,
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2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. On October 29, 2008, we moved for summary disposition of the claim that Oasis unduly discriminated against non-affiliated shippers and unduly preferred affiliated shippers. The presiding administrative law judge granted this motion on November 18, 2008, holding that FERC Staff had failed to make a prima facie case in support of this claim. This ruling, if allowed to stand, significantly narrows the FERC’s Oasis-related claims in the Order and Notice proceeding. The FERC also seeks to revoke, for a period of 12 months, our blanket marketing authority for sales of natural gas in interstate commerce at market-based prices, which activity is expected to account for approximately 1.0% of our operating income for our 2008 year. If the FERC is successful in revoking our blanket marketing authority, our sales of natural gas at market-based prices would be limited to sales to retail customers (such as utilities and other end-users) and sales from our own production, and any other sales of natural gas by us would be required to be made at contract prices that would be subject to individual FERC approval.
In its Order and Notice, the FERC specified that it was seeking $70.1 million in disgorgement of profits, plus interest, and $97.5 million in civil penalties relating to these matters. The FERC has taken the position that, once it receives our response, it has several options as to how to proceed, including issuing an order on the merits, requesting briefs, or setting specified issues for a trial-type hearing before an administrative law judge. On August 27, 2007, ETP filed a request for rehearing of the Order and Notice. On December 20, 2007, the FERC issued an order denying rehearing and directed the FERC Enforcement Staff to file a brief recommending disposition of issues by order or by evidentiary hearing. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERC’s claims and requested a dismissal of the FERC proceeding. On February 14, 2008, the Enforcement Staff of the FERC filed a brief recommending that the FERC refer various matters relating to its market manipulation allegations for an evidentiary hearing before a FERC administrative law judge. The Enforcement Staff also recommended that the FERC issue an order assessing the $15.5 million portion of the above-referenced penalty against ETP with respect to the allegations related to ETP’s Oasis pipeline and that the Oasis-related penalty assessment, if not paid, then be referred by the FERC to a federal district court for de novo review. The Enforcement Staff also recommended that the FERC impose certain changes in Oasis’s business operations and refunds to certain Oasis customers as previously proposed in the Order and Notice. Finally, the Enforcement Staff recommended that the FERC pursue market manipulation claims related to ETP’s trading activities in October 2005, for November 2005 monthly deliveries, a period not previously covered by FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month. If the FERC pursues the claims related to this additional month, the total amount of civil penalties and disgorgement of profits sought by the FERC would be approximately $200.0 million. On March 31, 2008, we responded to the Enforcement Staff’s brief. On May 15, 2008, the FERC ordered hearings to be conducted by FERC administrative law judges with respect to the FERC’s Oasis claims and market manipulation claims. The hearing related to the Oasis claims was scheduled to commence in December 2008 with the administrative law judge’s initial decisions due by May 11, 2009, however, as discussed below, ETP entered into a settlement agreement with FERC Enforcement Staff and that agreement was approved by the FERC in its entirety and without modification on February 27, 2009. The hearing related to the market manipulation claims is now scheduled to commence in June 2009 with the administrative law judge’s initial decision due by December 3, 2009. The FERC also ordered that, following the completion of the hearings, the administrative law judges make initial findings with respect to whether we engaged in market manipulation in violation of the NGA and FERC regulations and whether Oasis violated the NGPA and FERC regulations. The FERC reserved for itself the issues of possible civil penalties, revocation of our blanket market certificate, the method by which we and Oasis would disgorge any unjust profits and whether any conditions should be placed on Oasis’s Section 311 authorization. Following the issuance of each of the administrative law judges’ initial decisions, the FERC would then issue an order with respect to each of these matters. On May 23, 2008, we requested rehearing and stay of the FERC’s May 15, 2008 order establishing hearing, and we renewed those requests on June 26, 2008. On August 7, 2008, FERC denied rehearing of its May 15, 2008 order. On August 8, 2008, we filed a petition with the U.S. Court of Appeals for the Fifth Circuit to review and set aside FERC’s May 15 and August 7, 2008 orders on the grounds that we are entitled to adjudicate FERC’s claims in federal district court pursuant to the NGA and the NGPA. On August 28, 2008, we filed an amended petition seeking review of the Order and Notice and the December 20, 2007 order denying rehearing.
On November 18, 2008, the administrative law judge presiding over the Oasis claims granted ETP’s motion for summary disposition of the claim that Oasis unduly discriminated in favor of affiliates regarding the provision of Section 311(a)(2)
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interstate transportation service. ETP subsequently entered into an agreement with the Enforcement Staff to settle all of the claims related to Oasis. On January 5, 2009, this agreement was submitted under seal to FERC by the presiding administrative law judge, for FERC’s approval as an uncontested settlement of all Oasis claims. On February 27, 2009, the settlement agreement was approved by the FERC in its entirety and without modification and the terms of the settlement were made public. If no person seeks rehearing of the order approving the settlement within 30 days of such order, the FERC’s order will become final and non-appealable. We do not believe the Oasis settlement, as approved by the FERC, will have a material adverse effect on our business, financial condition or results of operations.
It is our position that our trading and transportation activities during the periods at issue complied in all material aspects with applicable law and regulations, and we intend to contest these cases vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC holds substantial enforcement authority. At this time, we are unable to predict the final outcome of these matters.
On July 26, 2007, the United States Commodity Futures Trading Commission (the “CFTC”) filed suit in United States District Court for the Northern District of Texas alleging that we violated provisions of the Commodity Exchange Act (“CEA”) by attempting to manipulate natural gas prices in the Houston Ship Channel. On March 17, 2008, we entered into a consent order with the CFTC (the “Consent Order”). Pursuant to the Consent Order, we agreed to pay the CFTC $10.0 million and the CFTC agreed to release us and our affiliates, directors and employees from all claims or causes of action asserted by the CFTC in this proceeding. The Consent Order provides that we are permanently enjoined from attempting to manipulate the price of any commodity in interstate commerce in violation of the CEA. By consenting to the entry of the Consent Order, we neither admitted nor denied the allegations made by the CFTC in this proceeding. The settlement reduced our existing accrual and was paid from cash flow from operations in March 2008.
In addition to the FERC legal action, third parties have asserted claims and may assert additional claims against us and ETE for damages related to these matters. In this regard, several natural gas producers and a natural gas marketing company have initiated legal proceedings in Texas state courts against us and ETE for claims related to the FERC claims. These suits contain contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006, and seek unspecified direct, indirect, consequential and exemplary damages. One of the suits against us and ETE contains an additional allegation that we and ETE transported gas in a manner that favored our affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. We have moved to compel arbitration and/or contested subject-matter jurisdiction in some of these cases. One such case currently is on appeal before the Texas Supreme Court on, among other things, the issue of whether the dispute is arbitrable.
We have also been served with a complaint from an owner of royalty interests in natural gas producing properties, individually and on behalf of a putative class of similarly situated royalty owners, working interest owners and producer/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. We filed an original action in Harris County state court seeking a stay of the arbitration on the ground that the action is not arbitrable, and the state court granted our motion for summary judgment on that issue. The claimants have filed a notice of appeal.
A consolidated class action complaint has been filed against us in the United States District Court for the Southern District of Texas. This action alleges that we engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the New York Mercantile Exchange, or NYMEX, in violation of the CEA. It is further alleged that during the class period December 29, 2003 to December 31, 2005, we had the market power to manipulate index prices, and that we used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, in order to benefit our natural gas physical and financial trading positions, and that we intentionally submitted price and volume trade information to trade publications. This complaint also alleges that we violated the CEA by knowingly aiding and abetting violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by us manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period, causing unspecified damages to the plaintiffs and all other members of the putative class who sold natural gas futures or who purchased and/or sold natural gas options contracts on NYMEX during the class period. The plaintiffs have requested certification of their suit as a class action and seek unspecified damages, court costs and other appropriate relief. On January 14, 2008, we filed a motion to
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dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. On March 20, 2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, on May 5, 2008, we filed a motion to dismiss the complaint. On June 19, 2008, the plaintiffs filed a response opposing our motion to dismiss. We filed a reply in support of our motion on July 9, 2008.
On March 17, 2008, a second class action complaint was filed against us in the United States District Court for the Southern District of Texas. This action alleges that we engaged in unlawful restraint of trade and intentional monopolization and attempted monopolization of the market for fixed-price natural gas baseload transactions at the Houston Ship Channel from December 2003 through December 2005 in violation of federal antitrust law. The complaint further alleges that during this period we exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to benefit our own physical natural gas positions. The plaintiff has, individually and on behalf of all other similarly situated sellers of physical natural gas, requested certification of its suit as a class action and seeks unspecified treble damages, court costs and other appropriate relief. On May 19, 2008, we filed a motion to dismiss this complaint. On July 2, 2008 the plaintiffs filed a response opposing our motion to dismiss. We filed a reply in support of our motion on August 18, 2008.
We are expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the outcome of these matters. However, it is possible that the amount we become obliged to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of our existing accrual related to these matters. In accordance with applicable accounting standards, we will review the amount of our accrual related to these matters as developments related to these matters occur and we will adjust our accrual if we determine that it is probable that the amount we may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of our existing accrual for these matters. As our accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce our cash available to service our indebtedness either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, we may experience a material adverse impact on our results of operations and our liquidity.
In re Natural Gas Royalties Qui Tam Litigation. MDL Docket No. 1293 (D. WY), Jack Grynberg, an individual, has filed actions against a number of companies, including Transwestern, now transferred to the U.S. District Court for the District of Wyoming, for damages for mis-measurement of gas volumes and Btu content, resulting in lower royalties to mineral interest owners. On October 20, 2006, the District Judge adopted in part the earlier recommendation of the Special Master in the case and ordered the dismissal of the case against Transwestern. Transwestern believes that its measurement practices conformed to the terms of its FERC Gas Tariff, which were filed with and approved by the FERC. As a result, Transwestern believes that is has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of the FERC, and the defense that Transwestern complied with the terms of its tariffs) and will continue to vigorously defend against them, including any appeal which may be taken from the dismissal of the Grynberg case. A hearing was held on April 24, 2007 regarding Transwestern’s Supplemental Brief for Attorneys’ fees which was filed on January 8, 2007 and the issues are submitted and are awaiting a decision. Grynberg moved to have the cases he appealed remanded to the district court for consideration in light of a recently-issued Supreme Court case. The defendants/appellees opposed the motion. The Tenth Circuit motions panel referred the remand motion to the merits panel to be carried with the appeals. Grynberg’s opening brief was filed on or about July 31, 2007. Appellee’s opposition brief was filed on or about November 21, 2007. Appellee Transwestern filed its separate response brief on January 11, 2008 and Grynberg’s reply brief was filed in June 2008 and the hearing on all briefs was held in September 2008, with a ruling expected in the near future. Transwestern does not believe the outcome of this case will have a material adverse effect on its financial position, results of operations or cash flows.
Transwestern Trespass Actions. Transwestern is managing one threatened trespass action related to right of way (“ROW”) on Tribal or allottee land. The threatened action concerns 5,100 feet of ROW on private allotments within the Laguna Pueblo that expired on December 28, 2002. Transwestern received a letter dated March 19, 2003 from the United States Department of the Interior, Bureau of Indian Affairs (“BIA”) on behalf of the two allottees asserting trespass. The matter has been fully resolved as of September 2008 and Transwestern has obtained ROW grants that are effective through December 27, 2022.
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Another action involves an agreement with the BIA covering 44 miles of ROW on a total of 68 Navajo allotments. This ROW agreement expired on January 1, 2004. One allottee sent a letter dated January 16, 2004 to the BIA claiming Transwestern trespassed and that allotee’s claim of trespass has been settled and his consent to use the property has been acquired. Transwestern filed a renewal application with the BIA during October 2002, and has received two grants from the BIA for allotted lands in New Mexico and Arizona, which are effective through December 31, 2023.
Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”), their parent companies and American Electric Power Corporation (“AEP”), were 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 (approximately $1.00 billion in the aggregate). The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters. On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the HPL Entities of approximately $347.3 million less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel Storage Facility. AEP is appealing the court decision. Based on the indemnification provisions of the Cushion Gas Litigation Agreement, ETP does not expect that it will be liable for any portion of this court award.
Other Matters. In addition to those matters described above, we or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and it is possible that the outcome of a particular matter will result in the payment of an amount in excess of the amount accrued for the matter. As our accrual amounts are non-cash, any cash payment of an amount in resolution of a particular matter would likely be made from cash from operations or borrowings. If cash payments to resolve a particular matter substantially exceed our accrual for such matter, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.
As of December 31, 2008 an accrual of $20.8 million, was recorded as accrued and other current liabilities and other non-current liabilities on our consolidated balance sheet for ETP’s 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,
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occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the clean up activities include remediation of several compressor sites on the Transwestern system for contamination by polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2018 is $9.1 million. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.
Transwestern continues to incur certain costs related to PCBs that could migrate through its pipelines into customers’ facilities. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remediation activities totaled approximately $0.8 million for the period since acquisition. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers, and accordingly, no accrual has been established for these costs at December 31, 2008. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.
Environmental regulations were recently modified for the EPA’s Spill Prevention, Control and Countermeasures (“SPCC”) program. We are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.
In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the “EPA”) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by HOLP was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). We have not received any follow-up correspondence from the EPA on the matter since our acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.
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 amount has been recorded in our December 31, 2008 consolidated balance sheet. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.
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 December 31, 2008 an accrual on an undiscounted basis of $13.3 million was recorded in our consolidated balance sheet
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as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition, the Transwestern acquisition, and the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for all of the above environmental matters is adequate to cover the potential exposure for clean-up costs.
ETP’s pipeline operations are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Hazardous Materials Safety Administration (“PHMSA”), pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas”. Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing, or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Through December 31, 2008, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2009. Through December 31, 2008, a total of $16.4 million of capital costs and $12.7 million of operating and maintenance costs have been incurred for pipeline integrity testing for our transportation assets other than Transwestern. Through December 31, 2008, a total of $6.9 million of capital costs and $0.4 million of operating and maintenance costs have been incurred for pipeline integrity costs for Transwestern. 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 its pipelines.
| 9. | PRICE RISK MANAGEMENT ASSETS AND LIABILITIES: |
Commodity Price Risk
We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To reduce the impact of this price volatility, we primarily 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. We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. Furthermore, on a bi-weekly basis, management reviews the creditworthiness of the derivative counterparties to manage against the risk of default.
ETP uses a combination of derivative 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.
ETP has maintenance margin deposits with certain counterparties in the OTC market and with clearing brokers. 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 ETP on the settlement date. We had net deposits with derivative counterparties and clearing brokers of $78.2 million as of December 31, 2008 reflected as deposits paid to vendors on our consolidated balance sheet.
We disclose the non-exchange traded financial derivatives instruments as price risk assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated contract date. We
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exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in the deposits paid to vendor on the consolidated balance sheet.
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
If ETP designates a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in fair value is deferred in Accumulated Other Comprehensive Income (“AOCI”) until the underlying hedged transaction recorded in earnings. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction recorded in earnings, 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 fair value is recorded each period in earnings.
In the course of normal operations, ETP routinely enters 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 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. As of December 31, 2008, these contracts have settled and are no longer reflected on our consolidated balance sheet.
Trading Activities
Due to a high level of market volatility as well as other business considerations, as of July 2008 ETP determined that it will no longer engage in the trading of financial derivative instruments that are not offset by physical positions. As a result, we will no longer have any material exposure to market risk from such derivative positions. The derivative contracts that are entered into for trading purposes, subject to limits, are recognized on the consolidated balance sheets at fair value.
The following table details the outstanding commodity-related derivatives as of December 31, 2008:
| Commodity | Notional Volume MMBTU | Maturity | Fair Value Asset (Liability) | |||||||
Mark to Market Derivatives | ||||||||||
Basis Swaps IFERC/NYMEX | Gas | 15,720,000 | 2009-2011 | 3,125 | ||||||
Swing Swaps IFERC | Gas | (58,045,000 | ) | 2009 | (118 | ) | ||||
Fixed Swaps/Futures | Gas | (20,880,000 | ) | 2009-2010 | 97,498 | |||||
Forwards/Swaps - in Gallons | Propane | 47,313,002 | 2009 | (42,288 | ) | |||||
Cash Flow Hedging Derivatives | ||||||||||
Basis Swaps IFERC/NYMEX | Gas | (9,085,000 | ) | 2009 | 3,268 | |||||
Fixed Swaps/Futures | Gas | (9,085,000 | ) | 2009 | 6,691 | |||||
ETP attempts 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 ETP’s 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.
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Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance ETP’s positions. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably.
ETP has discontinued the application of hedge accounting in connection with certain derivative financial instruments that had previously been qualified and designated as cash flow hedges related to forecasted sales of natural gas stored in our Bammel storage facilities. The discontinuation resulted from management’s determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable of occurring by the end of the originally specified time period, or within an additional two-month period of time thereafter.
Interest Rate Risk
ETP is exposed to market risk for changes in interest rates related to our bank credit facilities. To the extent interest rates increase, our interest expense for our revolving credit facilities will also increase. ETP manages a portion of its interest rate exposures by utilizing interest rate swaps and similar arrangements which allows ETP to effectively convert a portion of variable rate debt into fixed rate debt. Certain of ETP’s interest rate derivatives are accounted for as cash flow hedges. At December 31, 2008, we had $912.0 million of variable rate debt outstanding and a pay fixed receive float interest rate swap with a notional amount of $125.0 million that is not designated as a hedge. Changes in fair value of the swap are recorded in earnings. The last leg of this swap has been fixed and it is no longer subject to volatility. Additionally, ETP entered into forward starting swaps in December 2008 with a notional amount of $500.0 million.
Credit Risk
ETP maintains credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.
ETP’s 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 as a result of counterparty performance.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheet.
| 10. | RELATED PARTY TRANSACTIONS: |
Enterprise GP Holding, L.P. (“Enterprise” or “EPE”) and its subsidiaries are considered related parties since acquiring a 34.9% non-controlling interest in ETE’s General Partner, LE GP, L.L.C. (“LE GP”) in May 2007.
ETC OLP and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines, and ETC OLP sells natural gas to Enterprise. Our propane operations routinely buy and sell product with Enterprise. The following table summarizes the related party balances with Enterprise on our consolidated balance sheet at December 31, 2008:
Natural Gas Operations: | ||||
Accounts receivable | $ | 11,558 | ||
Accounts payable | 567 | |||
Imbalance payable | (547 | ) | ||
Propane Operations: | ||||
Accounts receivable | $ | 111 | ||
Accounts payable | 33,308 | |||
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Accounts receivable from related companies excluding Enterprise consist of the following at December 31, 2008:
ETE | $ | 2,632 | |
MEP | 2,805 | ||
Energy Transfer Technologies, Ltd. | 16 | ||
McReynolds Energy | 202 | ||
Others | 449 | ||
Total accounts receivable from related companies excluding Enterprise | $ | 6,104 | |
ETP’s natural gas midstream and intrastate transportation and storage operations secure compression services from third parties including Energy Transfer Technologies, Ltd., of which Energy Transfer Group, LLC is the General Partner. These entities are collectively referred to as the “ETG Entities”. The Chief Executive Officer of ETP GP has an indirect ownership in the ETG Entities. In addition, two of ETP’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 ETP, no less favorable than those available from other providers of compression services. As of December 31, 2008, accounts receivable from ETG related to compressor leases were $0.02 million.
| 11. | SUPPLEMENTAL INFORMATION: |
Following is the balance sheet of the Company, which is included to provide additional information with respect to ETP LLC’s financial position on a stand-alone basis as of December 31, 2008:
| ASSETS | |||
Investment in affilliates | $ | 16 | |
| MEMBER’S EQUITY | |||
Member’s Equity | $ | 16 | |
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