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The information in this preliminary prospectus supplement is not complete and may be changed. This preliminary prospectus supplement and the accompanying prospectus are not an offer to sell these securities and they are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted. |
Per | Total | Per | Total | |||||||||||||
2017 Note | 2017 Notes | 2020 Note | 2020 Notes | |||||||||||||
Price to Public(1) | % | $ | % | $ | ||||||||||||
Underwriting Discount | % | $ | % | $ | ||||||||||||
Proceeds to Energy Transfer Equity, L.P. (Before Expenses) | % | $ | % | $ |
(1) | Plus accrued interest from , 2010, if settlement occurs after that date. |
Credit Suisse |
Morgan Stanley |
Wells Fargo Securities |
BofA Merrill Lynch |
UBS Investment Bank |
BNP PARIBAS |
Deutsche Bank Securities |
SunTrust Robinson Humphrey |
Page | ||||
S-1 | ||||
S-15 | ||||
S-43 | ||||
S-44 | ||||
S-46 | ||||
S-48 | ||||
S-85 | ||||
S-105 | ||||
S-108 | ||||
S-110 | ||||
S-116 | ||||
S-136 | ||||
S-141 | ||||
S-143 | ||||
S-143 | ||||
A-1 |
Prospectus | ||||
About This Prospectus | 1 | |||
Energy Transfer Equity, L.P. | 1 | |||
Energy Transfer Partners, L.P. | 1 | |||
Cautionary Statement Concerning Forward-Looking Statements | 2 | |||
Risk Factors | 4 | |||
Use of Proceeds | 4 | |||
Ratio of Earnings to Fixed Charges | 4 | |||
Description of Debt Securities | 5 | |||
Plan of Distribution | 8 | |||
Legal Matters | 9 | |||
Experts | 9 | |||
Where You Can Find More Information | 10 | |||
Incorporation of Certain Documents by Reference | 10 |
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• | the accompanying prospectus, which provides general information, some of which may not apply to the notes; and | |
• | this prospectus supplement, which provides a summary of the specific terms of the notes. |
• | our Annual Report onForm 10-K for the year ended December 31, 2008; |
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• | our Quarterly Reports onForm 10-Q for the quarters ended March 31, 2009, June 30, 2009 and September 30, 2009; | |
• | our Current Reports onForm 8-K filed January 26, 2009, March 18, 2009, July 29, 2009, October 28, 2009, December 23, 2009 and January 20, 2010; and | |
• | all documents filed by us under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 between the date of this prospectus supplement and before the termination of this offering. |
• | the ability of our subsidiary, Energy Transfer Partners, L.P., or ETP, to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP; | |
• | the actual amount of cash distributions by ETP to us, which is affected by the amount, if any, of cash reserves established by the Board of Directors of the general partner of ETP and is outside of our control; | |
• | the amount of natural gas transported on ETP’s pipelines and gathering systems; | |
• | the level of throughput in ETP’s natural gas processing and treating facilities; | |
• | the fees ETP charges and the margins it realizes for its gathering, treating, processing, storage and transportation services; | |
• | the prices and market demand for, and the relationship between, natural gas and natural gas liquids, or NGLs; |
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• | energy prices generally; | |
• | the prices of natural gas and propane compared to the price of alternative and competing fuels; | |
• | the general level of petroleum product demand and the availability and price of propane supplies; | |
• | the level of domestic oil, propane and natural gas production; | |
• | the availability of imported oil and natural gas; | |
• | the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas; | |
• | actions taken by foreign oil and gas producing nations; | |
• | the political and economic stability of petroleum producing nations; | |
• | the effect of weather conditions on demand for oil, natural gas and propane; | |
• | availability of local, intrastate and interstate transportation systems; | |
• | the continued ability to find and contract for new sources of natural gas supply; | |
• | availability and marketing of competitive fuels; | |
• | the impact of energy conservation efforts; | |
• | energy efficiencies and technological trends; | |
• | governmental regulation and taxation; | |
• | changes to, and the application of, regulation of tariff rates and operational requirements related to ETP’s interstate and intrastate pipelines; | |
• | hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance; | |
• | the maturity of the propane industry and competition from other propane distributors; | |
• | competition from other midstream companies, interstate pipeline companies and propane distribution companies; | |
• | loss of key personnel; | |
• | loss of key natural gas producers or the providers of fractionation services; | |
• | reductions in the capacity or allocations of third-party pipelines that connect with ETP’s pipelines and facilities; | |
• | the effectiveness of risk-management policies and procedures and the ability of ETP’s liquids marketing counterparties to satisfy their financial commitments; | |
• | the nonpayment or nonperformance by ETP’s customers; | |
• | regulatory, environmental, political and legal uncertainties that may affect the timing and cost of ETP’s internal growth projects, such as ETP’s construction of additional pipeline systems; | |
• | risks associated with the construction of new pipelines and treating and processing facilities or additions to ETP’s existing pipelines and facilities, including difficulties in obtaining permits andrights-of-way or other regulatory approvals and the performance by third-party contractors; | |
• | the availability and cost of capital and ETP’s ability to access certain capital sources; | |
• | the further deterioration of the credit and capital markets; |
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• | the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to ETP’s financial results and to successfully integrate acquired businesses; | |
• | changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and | |
• | the costs and effects of legal and administrative proceedings. |
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S-1
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• | an approximate 1.8% general partner interest, which ETE holds through its ownership interests in ETP GP; | |
• | 100% of the incentive distribution rights in ETP, which ETE holds through its ownership interests in ETP GP; and | |
• | approximately 62.5 million ETP common units, all of which are held directly by ETE. |
• | 13.0% of all incremental cash distributed in a fiscal quarter after $0.275 has been distributed in respect of each common unit of ETP for that quarter; | |
• | 23.0% of all incremental cash distributed in a fiscal quarter after $0.3175 has been distributed in respect of each common unit of ETP for that quarter; and | |
• | the maximum sharing level of 48.0% of all incremental cash distributed in a fiscal quarter after $0.4125 has been distributed in respect of each common unit of ETP for that quarter. |
Nine Months | Four Months | |||||||||||||||||||
Ended | Year Ended | Ended | Year Ended | |||||||||||||||||
September 30, | December 31, | December 31, | August 31, | |||||||||||||||||
2009 | 2008 | 2008 | 2007 | 2007 | ||||||||||||||||
Limited Partner Interests | $ | 167,580 | $ | 166,018 | $ | 221,878 | $ | 70,313 | $ | 199,221 | ||||||||||
General Partner Interest | 14,588 | 12,740 | 17,322 | 5,110 | 13,676 | |||||||||||||||
Incentive Distribution Rights | 255,808 | 219,298 | 298,575 | 85,775 | 222,353 | |||||||||||||||
Total distributions received from ETP(1) | $ | 437,976 | $ | 398,056 | $ | 537,775 | $ | 161,198 | $ | 435,250 | ||||||||||
(1) | Represents cash distributions received in respect of each of the quarters included within the period, including distributions paid in respect of the last quarter of such period after the end of such quarter and excluding distributions paid during the first quarter of such period in respect of the prior quarter. |
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• | In April 2007, ETP completed its243-mile pipeline from Cleburne in north Texas to Carthage in east Texas, which we refer to as the Cleburne to Carthage pipeline, to expand its capacity to transport natural gas produced from the Barnett Shale and the Bossier Sands to its Texoma pipeline and other pipeline interconnections. The Cleburne to Carthage pipeline is primarily a42-inch diameter natural gas pipeline. In December 2007, ETP completed two natural gas compression projects that added approximately 90,000 horsepower on the Cleburne to Carthage pipeline, increasing natural gas deliverability at the Carthage Hub to more than 2.0 Bcf/d. | |
• | In April 2008, ETP completed its150-mile Southeast Bossier42-inch diameter natural gas pipeline, which we refer to as the Southeast Bossier pipeline. This pipeline connects ETP’s42-inch diameter Cleburne to Carthage pipeline and its30-inch diameter East Texas pipeline to its30-inch diameter Texoma pipeline. The Southeast Bossier pipeline has an initial throughput capacity of 900 million cubic feet per day, orMMcf/d, which can be increased to 1.3 Bcf/d with the addition of compression. The Southeast Bossier pipeline increases ETP’s takeaway capacity from the Barnett Shale and Bossier Sands and provides increased market access for natural gas produced in these areas. | |
• | In July 2008, ETP completed its36-inch diameter Paris Loop natural gas pipeline expansion project in north Texas. This135-mile pipeline initially provided ETP with an additional400 MMcf/d of capacity out of the Barnett Shale, which increased to900 MMcf/d in May 2009. The Paris Loop originates near Eagle Mountain Lake in northwest Tarrant County, Texas and connects to ETP’s Houston Pipe Line system near Paris, Texas. | |
• | In August 2008, ETP completed an expansion of its Cleburne to Carthage pipeline from the Texoma pipeline interconnect to the Carthage Hub through the installation of 32 miles of42-inch diameter pipeline. This expansion, which we refer to as the Carthage Loop, added500 MMcf/d of pipeline capacity from Cleburne to the Carthage Hub. In September 2009, ETP increased the capacity of the Carthage Loop to 1.1 Bcf/d by adding compression to this pipeline. |
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• | In August 2008, ETP completed the first segment of its36-inch diameter Maypearl to Malone natural gas pipeline expansion project. This25-mile pipeline extends from Maypearl, Texas to Malone, Texas, and provides an additional600 MMcf/d of capacity out of the Fort Worth Basin. | |
• | In January 2009, ETP completed its Southern Shale natural gas pipeline project, which consists of 31 miles of36-inch diameter pipeline that originates in southern Tarrant County, Texas and delivers natural gas to its Maypearl to Malone pipeline expansion project. The Southern Shale pipeline provides an additional700 MMcf/d of takeaway capacity from the Barnett Shale. | |
• | In January 2009, ETP completed its36-inch diameter Cleburne to Tolar natural gas pipeline expansion project. This20-mile pipeline extends from Cleburne, Texas to Tolar, Texas and provides an additional400 MMcf/d of takeaway capacity from the Barnett Shale. | |
• | In February 2009, ETP completed its56-mile Katy Expansion pipeline project. This36-inch diameter expansion project increases the capacity of its existing ETC Katy natural gas pipeline in southeast Texas by more than400 MMcf/d. | |
• | In August 2009, ETP completed its Texas Independence Pipeline, which consists of approximately 150 miles of42-inch diameter pipeline originating near Maypearl, Texas and ending near Henderson, Texas. This pipeline connects ETP’s ET Fuel System and North Texas System with its East Texas pipeline. The Texas Independence Pipeline expands ETP’s ET Fuel System’s throughput capacity by an incremental 1.1 Bcf/d and, with the addition of compression, the capacity may be expanded to 1.75 Bcf/d. |
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• | ETP believes that the size and scope of its operations, its stable asset base and cash flow profile, and its investment grade status will be significant positive factors in its efforts to obtain new debt or equity financing in light of current market conditions. |
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• | ETP’s experienced management team has an established reputation as highly-effective, strategic operators within its operating segments. In addition, ETP’s management team is motivated to effectively and efficiently manage its business operations through performance-based incentive compensation programs and through ownership of a substantial equity position in us and therefore benefits from incentive distribution payments ETP makes to ETP GP. |
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S-8
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(1) | Includes approximately 540,000 common units owned by management of Energy Transfer Partners, L.P. | |
(2) | Includes unamortized discounts of ETP senior notes. | |
(3) | Does not include the outstanding debt of joint ventures MEP and FEP. See “Capitalization” and “Description of Other Indebtedness.” |
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Issuer | Energy Transfer Equity, L.P. | |
Notes Offered | We are offering $1,750,000,000 aggregate principal amount of notes of the following series: | |
• $ % Senior Notes due 2017, and | ||
• $ % Senior Notes due 2020. | ||
Maturity | The 2017 notes will mature on February 28, 2017 and the 2020 notes will mature on February 28, 2020. | |
Interest Rate | Interest on the 2017 notes will accrue at the per annum rate of % and interest on the 2020 notes will accrue at the per annum rate of %. | |
Interest Payment Dates | Interest on the notes will accrue from the issue date of the notes and be payable semi-annually on February 28 and August 31 of each year, beginning on August 31, 2010. | |
Ranking | The notes will be our senior obligations. The notes will rank equally in right of payment with all of our other existing and future senior unsubordinated indebtedness and senior to any of our subordinated indebtedness. | |
The notes initially will not be guaranteed by any of our subsidiaries. However, if in the future any of our subsidiaries guarantees or becomes a co-obligor with respect to any indebtedness under our revolving credit facility, then such subsidiary will also guarantee the notes on terms provided for in the indenture. With respect to the assets of our subsidiaries that do not guarantee the notes, including ETP, the notes will effectively rank junior to all existing and future obligations of those subsidiaries. As of September 30, 2009, our subsidiaries, including ETP and its subsidiaries, had outstanding approximately $6.2 billion of indebtedness that would effectively rank senior to the notes with respect to the assets of those subsidiaries. | ||
The notes will be unsecured, and will effectively rank junior to our secured indebtedness to the extent of the value of collateral securing such indebtedness. Borrowings under our new revolving credit facility will be secured by a substantial portion of our assets. | ||
Optional Redemption | We may redeem the notes in whole, at any time, or in part, from time to time, prior to maturity, at a redemption price that includes accrued and unpaid interest and a make-whole premium. See “Description of Notes — Optional Redemption” beginning onpage S-118. |
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Covenants | We will issue the notes under an indenture with U.S. Bank National Association, as trustee. The covenants in the indenture include a limitation on liens and a restriction on sale-leaseback transactions. The covenants will generally not apply to ETP and its subsidiaries. Each covenant is subject to a number of important exceptions, limitations and qualifications that are described in “Description of Notes” under the heading “Covenants.” | |
Mandatory Offer to Repurchase | If we experience a change of control together with a rating decline, each as defined in the indenture, we must offer to repurchase the notes at an offer price in cash equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase. See “Description of Notes — Covenants.” | |
Use of Proceeds | We anticipate using approximately $124 million of the net proceeds of this offering to repay all of the outstanding indebtedness under our existing revolving credit facility and approximately $1.45 billion of the net proceeds of this offering to repay indebtedness outstanding under our term loan facility. In addition, we anticipate using the remaining approximately $144 million of the net proceeds of this offering to fund a portion of the estimated cost to terminate interest rate swap agreements relating to these outstanding borrowings. We anticipate funding the remaining $14.3 million of estimated costs to terminate these interest rate swap agreements with borrowings under our new $200 million senior secured revolving credit facility, which we will enter into contemporaneously with the consummation of this offering and the repayment of outstanding indebtedness under our existing revolving credit facility. See “Use of Proceeds” and “Description of Other Indebtedness.” | |
Governing Law | The indenture and the notes provide that they will be governed by, and construed in accordance with, the laws of the state of New York. | |
Risk Factors | Investing in the notes involves risks. See “Risk Factors” beginning on pageS-15 of this prospectus supplement and the other risks identified in the documents incorporated by reference herein for information regarding risks you should consider before investing in the notes. | |
Original Issue Discount | The notes may be issued with original issue discount, or OID, for U.S. federal income tax purposes. If the notes are issued with OID, then such OID will accrue from the date of issuance of the notes and will be included as interest income in a U.S. holder’s gross income for U.S. federal income tax purposes in advance of receipt of the cash payments to which such income is attributable, regardless of such holder’s method of tax accounting. See “Certain United States Federal Income and Estate Tax Considerations — Tax Consequences to U.S. Holders — Stated Interest and OID on the Notes.” |
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Four Months | ||||||||||||||||||||||||
Nine Months Ended | Year Ended | Ended | ||||||||||||||||||||||
September 30, | December 31, | December 31, | Years Ended August 31, | |||||||||||||||||||||
2009 | 2008 | 2008 | 2007 | 2007 | 2006 | |||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||
Intrastate transportation and storage segment | $ | 1,589,298 | $ | 4,862,641 | $ | 5,634,604 | $ | 1,254,401 | $ | 3,915,932 | $ | 5,013,224 | ||||||||||||
Interstate transportation segment | 203,349 | 176,663 | 244,224 | 76,000 | 178,663 | — | ||||||||||||||||||
Midstream segment | 1,750,466 | 4,555,340 | 5,342,393 | 1,166,313 | 2,853,496 | 4,223,544 | ||||||||||||||||||
Eliminations | (540,075 | ) | (3,272,574 | ) | (3,568,065 | ) | (664,522 | ) | (1,562,199 | ) | (2,359,256 | ) | ||||||||||||
Retail propane and other retail propane related segment | 902,471 | 1,162,941 | 1,624,010 | 511,258 | 1,284,867 | 879,556 | ||||||||||||||||||
Other | 6,004 | 13,675 | 16,201 | 5,892 | 121,278 | 102,028 | ||||||||||||||||||
Total revenues | 3,911,513 | 7,498,686 | 9,293,367 | 2,349,342 | 6,792,037 | 7,859,096 | ||||||||||||||||||
Gross margin | 1,648,233 | 1,761,442 | 2,355,287 | 675,688 | 1,713,831 | 1,290,780 | ||||||||||||||||||
Depreciation and amortization | 239,626 | 200,922 | 274,372 | 75,406 | 191,383 | 129,636 | ||||||||||||||||||
Operating income | 744,630 | 846,133 | 1,098,903 | 316,651 | 809,336 | 575,540 | ||||||||||||||||||
Interest expense, net of interest capitalized | (341,050 | ) | (261,297 | ) | (357,541 | ) | (103,375 | ) | (279,986 | ) | (150,646 | ) | ||||||||||||
Income before income tax expense | 461,548 | 625,692 | 683,562 | 192,758 | 563,359 | 433,907 | ||||||||||||||||||
Income tax expense | 5,773 | 6,600 | 3,808 | 9,949 | 11,391 | 23,015 | ||||||||||||||||||
Net income attributable to noncontrolling interest | 152,893 | 266,614 | 304,710 | 90,132 | 232,608 | 303,752 | ||||||||||||||||||
Net income attributable to partners | 302,882 | 352,478 | 375,044 | 92,677 | 319,360 | 107,140 | ||||||||||||||||||
Balance Sheet Data (at period end): | ||||||||||||||||||||||||
Current assets | 858,411 | 1,779,940 | 1,180,995 | 1,403,796 | 1,050,578 | 1,302,735 | ||||||||||||||||||
Total assets | 11,684,508 | 11,267,924 | 11,069,902 | 9,462,094 | 8,183,089 | 5,924,141 | ||||||||||||||||||
Current liabilities | 882,387 | 1,322,535 | 1,208,921 | 1,241,433 | 932,815 | 1,020,787 | ||||||||||||||||||
Long-term debt, less current maturities | 7,740,135 | 7,181,710 | 7,190,357 | 5,870,106 | 5,198,676 | 3,205,646 | ||||||||||||||||||
Total equity | 2,753,663 | 47,969 | 2,339,316 | 2,091,156 | 1,835,300 | 1,484,878 |
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Four Months | ||||||||||||||||||||||||
Nine Months Ended | Year Ended | Ended | ||||||||||||||||||||||
September 30, | December 31, | December 31, | Years Ended August 31, | |||||||||||||||||||||
2009 | 2008 | 2008 | 2007 | 2007 | 2006 | |||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||
Cash flow provided by operating activities | 721,421 | 908,837 | 1,143,720 | 208,635 | 1,006,320 | 502,928 | ||||||||||||||||||
Cash flow used in investing activities | (1,225,719 | ) | (1,439,741 | ) | (2,015,585 | ) | (995,943 | ) | (2,158,090 | ) | (1,244,406 | ) | ||||||||||||
Cash flow provided by financing activities | 462,467 | 1,100,479 | 907,331 | 766,515 | 1,202,916 | 734,223 | ||||||||||||||||||
Capital expenditures: | ||||||||||||||||||||||||
Maintenance (accrual basis) | 71,766 | 75,931 | 140,966 | 48,998 | 89,226 | 51,826 | ||||||||||||||||||
Growth (accrual basis) | 534,696 | 1,532,458 | 1,921,679 | 604,371 | 998,075 | 677,861 | ||||||||||||||||||
Acquisition | 6,244 | 62,002 | 84,783 | 337,092 | 90,695 | 586,185 |
Four Months | ||||||||||||||||||||||||
Nine Months Ended | Year Ended | Ended | ||||||||||||||||||||||
September 30, | December 31, | December 31, | Years Ended August 31, | |||||||||||||||||||||
2009 | 2008 | 2008 | 2007 | 2007 | 2006 | |||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||
Equity in earnings of affiliates | $ | 370,195 | $ | 441,299 | $ | 551,835 | $ | 168,547 | $ | 435,247 | $ | 204,987 | ||||||||||||
Selling, general and administration expense | (3,608 | ) | (4,523 | ) | (6,453 | ) | (2,875 | ) | (8,496 | ) | (55,374 | ) | ||||||||||||
Interest expense | (56,728 | ) | (69,527 | ) | (91,822 | ) | (37,071 | ) | (104,405 | ) | (36,773 | ) | ||||||||||||
Losses on non-hedged interest rate derivatives | (7,954 | ) | (13,759 | ) | (77,435 | ) | (27,670 | ) | (1,952 | ) | — | |||||||||||||
Losses on extinguishment of debt | — | — | — | — | — | (5,060 | ) | |||||||||||||||||
Other, net | 329 | (993 | ) | (1,056 | ) | (8,128 | ) | (405 | ) | (638 | ) | |||||||||||||
Net income | $ | 302,882 | $ | 352,478 | $ | 375,044 | $ | 92,677 | $ | 319,360 | $ | 107,140 | ||||||||||||
Balance Sheet Data (at period end): | ||||||||||||||||||||||||
Current assets | 1,759 | 100,842 | 684 | 11,694 | 25,783 | 1,899 | ||||||||||||||||||
Total assets | 1,653,787 | 1,800,706 | 1,671,339 | 1,630,940 | 1,537,875 | 668,488 | ||||||||||||||||||
Current liabilities | 74,831 | 39,741 | 61,419 | 27,978 | 10,507 | 5,331 | ||||||||||||||||||
Long-term debt, less current maturities | 1,573,923 | 1,672,026 | 1,571,642 | 1,572,643 | 1,571,500 | 616,291 | ||||||||||||||||||
Cash Flow Data: | ||||||||||||||||||||||||
Cash flow provided by operating activities | $ | 349,402 | $ | 329,150 | $ | 436,819 | $ | 77,360 | $ | 239,777 | $ | 110,554 | ||||||||||||
Cash flow provided by financing activities | (349,402 | ) | (229,192 | ) | (436,799 | ) | (85,919 | ) | 968,689 | 16,142 | ||||||||||||||
Distributable Cash Flow: | ||||||||||||||||||||||||
Distributions related to period expected from ETP: | ||||||||||||||||||||||||
Limited partner interests | 167,580 | 166,018 | 221,878 | 70,313 | 199,221 | 91,127 | ||||||||||||||||||
General partner interests | 14,588 | 12,740 | 17,322 | 5,110 | 13,676 | 8,090 | ||||||||||||||||||
Incentive distribution rights | 255,808 | 219,298 | 298,575 | 85,775 | 222,353 | 71,513 | ||||||||||||||||||
Total distributions related to period expected from ETP | 437,976 | 398,056 | 537,775 | 161,198 | 435,250 | 170,730 | ||||||||||||||||||
ETE related expenses | (2,205 | ) | (5,600 | ) | (7,007 | ) | (11,288 | ) | (10,343 | ) | (3,404 | ) | ||||||||||||
Interest expense, net of amortization of financing costs, interest income, and realized gains and losses on interest rate derivatives | (70,342 | ) | (74,218 | ) | (97,654 | ) | (34,748 | ) | (100,933 | ) | (35,279 | ) | ||||||||||||
Distributable Cash Flow | $ | 365,429 | $ | 318,238 | $ | 433,114 | $ | 115,162 | $ | 323,974 | $ | 132,047 | ||||||||||||
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Four Months | ||||||||||||||||||||||||
Nine Months Ended | Year Ended | Ended | ||||||||||||||||||||||
September 30, | December 31, | December 31, | Years Ended August 31, | |||||||||||||||||||||
2009 | 2008 | 2008 | 2007 | 2007 | 2006 | |||||||||||||||||||
Reconciliation of Net income to Distributable Cash Flow: | ||||||||||||||||||||||||
Net income | $ | 302,882 | $ | 352,478 | $ | 375,044 | $ | 92,677 | $ | 319,360 | $ | 107,140 | ||||||||||||
Adjustments to derive Distributable Cash Flow: | ||||||||||||||||||||||||
Equity in income of unconsolidated affiliates | (370,195 | ) | (441,299 | ) | (551,835 | ) | (168,547 | ) | (435,247 | ) | (204,987 | ) | ||||||||||||
Distributions related to period expected from ETP | 437,976 | 398,056 | 537,775 | 161,198 | 435,251 | 170,730 | ||||||||||||||||||
Amortization included in interest | 5,236 | 2,255 | 5,076 | 1,006 | 2,630 | 1,151 | ||||||||||||||||||
Unrealized (gains) losses on non-hedged interest rate swaps | (10,885 | ) | 6,734 | 66,231 | 28,805 | 1,952 | — | |||||||||||||||||
Other non-cash | 415 | 14 | 823 | 23 | 28 | 58,013 | ||||||||||||||||||
Distributable Cash Flow | $ | 365,429 | $ | 318,238 | $ | 433,114 | $ | 115,162 | $ | 323,974 | $ | 132,047 | ||||||||||||
Reconciliation of Cash flow provided by operating activities to Distributable Cash Flow: | ||||||||||||||||||||||||
Cash flow provided by operating activities | $ | 349,402 | $ | 329,150 | $ | 436,819 | $ | 77,360 | $ | 239,777 | $ | 110,554 | ||||||||||||
Adjustments to derive Distributable Cash Flow: | ||||||||||||||||||||||||
Distributions related to period expected from ETP | 437,976 | 398,056 | 537,775 | 161,198 | 435,251 | 170,730 | ||||||||||||||||||
Cash distributions received from ETP | (425,938 | ) | (399,295 | ) | (535,342 | ) | (110,878 | ) | (360,602 | ) | (149,283 | ) | ||||||||||||
Deferred income taxes | 649 | — | — | — | — | — | ||||||||||||||||||
Net changes in operating assets and liabilities | 3,340 | (9,673 | ) | (6,138 | ) | (12,518 | ) | 9,548 | 46 | |||||||||||||||
Distributable Cash Flow | $ | 365,429 | $ | 318,238 | $ | 433,114 | $ | 115,162 | $ | 323,974 | $ | 132,047 | ||||||||||||
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• | the amount of natural gas transported through ETP’s transportation pipelines and gathering systems; | |
• | the level of throughput in its processing and treating operations; | |
• | the fees it charges and the margins it realizes for its gathering, treating, processing, storage and transportation services; | |
• | the price of natural gas; | |
• | the relationship between natural gas and NGL prices; | |
• | the weather in its operating areas; | |
• | the cost of the propane it buys for resale and the prices it receives for its propane; | |
• | the level of competition from other midstream companies, interstate pipeline companies, propane companies and other energy providers; | |
• | the level of its operating costs; | |
• | prevailing economic conditions; and | |
• | the level of ETP’s hedging activities. |
• | the level of capital expenditures it makes; | |
• | the level of costs related to litigation and regulatory compliance matters; | |
• | the cost of acquisitions, if any; | |
• | the levels of any margin calls that result from changes in commodity prices; | |
• | its debt service requirements; |
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• | fluctuations in its working capital needs; | |
• | its ability to make working capital borrowings under its credit facilities to make distributions; | |
• | its ability to access capital markets; | |
• | restrictions on distributions contained in its debt agreements; | |
• | the amount, if any, of cash reserves established by the board of directors of its general partner in its discretion for the proper conduct of ETP’s business; and | |
• | applicable state partnership laws and other laws and regulations. |
• | a significant portion of ETP’s cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions by ETP to us; | |
• | covenants contained in ETP’s existing debt arrangements require ETP to meet financial tests that may adversely affect its flexibility in planning for and reacting to changes in its business; | |
• | ETP’s ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited; | |
• | ETP may be at a competitive disadvantage relative to similar companies that have less debt; | |
• | ETP may be more vulnerable to adverse economic and industry conditions as a result of its significant debt level; and |
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• | failure to comply with the various restrictive and affirmative covenants of the credit agreements could negatively impact ETP’s ability to incur additional debt and to pay distributions. |
• | to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs); | |
• | to reimburse our general partner for all expenses it has incurred on our behalf; | |
• | to provide funds for distributions to our unitholders and our general partner for any one or more of the next four calendar quarters; or | |
• | to comply with applicable law or any of our loan or other agreements. |
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• | voluntarily withdraws from the partnership by giving notice to the other partners; | |
• | transfers all, but not less than all, of its partnership interests to another entity in accordance with the terms of ETP’s Partnership Agreement; | |
• | makes a general assignment for the benefit of creditors, files a voluntary bankruptcy petition, seeks to liquidate, acquiesces in the appointment of a trustee, receiver or liquidator, or becomes subject to an involuntary bankruptcy petition; or | |
• | dissolves itself under Delaware law without reinstatement within the requisite period. |
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• | unitholders’ current proportionate ownership interest in ETP will decrease; | |
• | the amount of cash available for distribution on each common unit or partnership security may decrease; | |
• | the ratio of taxable income to distributions may increase; | |
• | the relative voting strength of each previously outstanding common unit may be diminished; and | |
• | the market price of ETP’s common units may decline. |
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• | the allocation of shared overhead expenses to ETP and us; | |
• | the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP, on the other hand; | |
• | the determination of the amount of cash to be distributed to ETP’s partners and the amount of cash to be reserved for the future conduct of ETP’s business; | |
• | the determination whether to make borrowings under ETP’s revolving credit facility to pay distributions to ETP’s partners; and | |
• | any decision we make in the future to engage in business activities independent of ETP. |
• | Our general partner is allowed to take into account the interests of parties other than us, including ETP and its affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us. | |
• | Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. |
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• | Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution. | |
• | Our general partner determines which costs it and its affiliates have incurred are reimbursable by us. | |
• | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us. | |
• | Our general partner controls the enforcement of obligations owed to us by it and its affiliates. | |
• | Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
• | permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner; | |
• | provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests; | |
• | generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and | |
• | provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. |
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• | the impact of weather on the demand for oil and natural gas; | |
• | the level of domestic oil and natural gas production; | |
• | the availability of imported oil and natural gas; | |
• | actions taken by foreign oil and gas producing nations; | |
• | the availability of local, intrastate and interstate transportation systems; | |
• | the price, availability and marketing of competitive fuels; | |
• | the demand for electricity; | |
• | the impact of energy conservation efforts; and | |
• | the extent of governmental regulation and taxation. |
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• | because ETP is unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them; | |
• | because ETP is unable to raise financing for such acquisitions on economically acceptable terms; or | |
• | because ETP is outbid by competitors, some of which are substantially larger than ETP and have greater financial resources and lower costs of capital then it does. |
• | fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements; | |
• | decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions; | |
• | significantly increase its interest expense or financial leverage if ETP incurs additional debt to finance acquisitions; | |
• | encounter difficulties operating in new geographic areas or new lines of business; | |
• | incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which ETP is not indemnified or for which the indemnity is inadequate; | |
• | be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets; | |
• | less effectively manage its historical assets, due to the diversion of ETP management’s attention from other business concerns; or | |
• | incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges. |
• | ETP is unable to identify pipeline construction opportunities with favorable projected financial returns; | |
• | ETP is unable to raise financing for its identified pipeline construction opportunities; or | |
• | ETP is unable to secure sufficient natural gas transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons. |
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• | operating terms and conditions of service; | |
• | the types of services interstate pipelines may offer their customers; | |
• | construction of new facilities; | |
• | acquisition, extension or abandonment of services or facilities; |
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• | reporting and information posting requirements; | |
• | accounts and records; and | |
• | relationships with affiliated companies involved in all aspects of the natural gas and energy businesses. |
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• | price; | |
• | reliability and quality of service; | |
• | responsiveness to customer needs; | |
• | safety concerns; | |
• | long-standing customer relationships; | |
• | the inconvenience of switching tanks and suppliers; and | |
• | the lack of growth in the industry. |
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• | an actual basis; | |
• | an as adjusted basis to give effect to: (1) ETP’s public offering of 6,900,000 common units in October 2009 and the related use of net proceeds of approximately $275.3 million to repay amounts outstanding under the ETP Credit Facility; (2) ETP’s issuance of an aggregate of 2,079,593 common units under its equity distribution program in November and December 2009 and the related use of net proceeds of approximately $89.7 million to repay amounts outstanding under the ETP Credit Facility; (3) Transwestern’s issuance of $350 million aggregate principal amount of senior notes in December 2009, the proceeds from which were ultimately used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes; and (4) ETP’s public offering of 9,775,000 common units in January 2010 and the related use of net proceeds of approximately $422.9 million to repay amounts outstanding under the ETP Credit Facility; and | |
• | an as further adjusted basis to give effect to the sale of the notes and the application of the net proceeds therefrom as described in “Use of Proceeds.” |
September 30, 2009 | ||||||||||||
As Further | ||||||||||||
Actual | As Adjusted | Adjusted | ||||||||||
(In thousands) | ||||||||||||
Cash and cash equivalents(1) | $ | 50,192 | $ | 703,201 | $ | 703,201 | ||||||
Debt, including current maturities: | ||||||||||||
Debt of Energy Transfer Equity | ||||||||||||
Existing $500 million Revolving Credit Facility | $ | 123,923 | $ | 123,923 | $ | — | ||||||
New $200 million Revolving Credit Facility | — | — | 14,300 | |||||||||
Term Loan Facility | 1,450,000 | 1,450,000 | — | |||||||||
2017 Notes offered hereby | — | — | ||||||||||
2020 Notes offered hereby | — | — | ||||||||||
Debt of Energy Transfer Partners(2)(3) | ||||||||||||
$2,000 million ETP Revolving Credit Facility | 483,265 | — | — | |||||||||
ETP Senior Notes | 5,050,000 | 5,050,000 | 5,050,000 | |||||||||
Transwestern Senior Notes | 520,000 | 870,000 | 870,000 | |||||||||
HOLP Senior Secured Notes | 144,912 | 144,912 | 144,912 | |||||||||
Other long-term debt | 27,159 | 27,159 | 27,159 | |||||||||
Unamortized discounts | (13,009 | ) | (13,009 | ) | (13,009 | ) | ||||||
Total long-term debt | 7,786,250 | 7,652,985 | 7,843,362 | |||||||||
Total Equity | 2,753,663 | 3,541,519 | 3,541,519 | |||||||||
Total Capitalization | $ | 10,539,913 | $ | 11,194,504 | $ | 11,384,881 | ||||||
(1) | As of December 31, 2009, ETE had cash and cash equivalents (on a consolidated basis) of $68.3 million. | |
(2) | On February 29, 2008, MEP entered into a credit agreement that provides for a $1.4 billion senior revolving credit facility, which we refer to as the MEP Facility. ETP has guaranteed 50% of the obligations of MEP under the MEP Facility, with the remaining 50% of MEP’s obligations guaranteed by KMP. In |
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September 2009, MEP issued $800 million of senior unsecured notes and used the proceeds to repay indebtedness under the MEP Facility. In November 2009, MEP entered into an amendment to the credit agreement related to the MEP Facility in order to reduce the borrowing capacity under the facility to $275.0 million. As of December 31, 2009, there were $29.5 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. | ||
(3) | On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility. ETP has guaranteed 50% of the obligations of FEP under this facility, with the remaining 50% of FEP’s obligations guaranteed by KMP. As of December 31, 2009, there were $355.0 million of outstanding borrowings under FEP’s senior revolving credit facility. |
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Four Months | ||||||||||||||||||||||||||||||||
Nine Months Ended | Year Ended | Ended | ||||||||||||||||||||||||||||||
September 30, | December 31, | December 31, | Years Ended August 31, | |||||||||||||||||||||||||||||
2009 | 2008 | 2008 | 2007 | 2007 | 2006 | 2005 | 2004 | |||||||||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||||||
Intrastate transportation and storage segment | $ | 1,589,298 | $ | 4,862,641 | $ | 5,634,604 | $ | 1,254,401 | $ | 3,915,932 | $ | 5,013,224 | $ | 2,608,108 | $ | 113,938 | ||||||||||||||||
Interstate transportation segment | 203,349 | 176,663 | 244,224 | 76,000 | 178,663 | — | — | — | ||||||||||||||||||||||||
Midstream segment | 1,750,466 | 4,555,340 | 5,342,393 | 1,166,313 | 2,853,496 | 4,223,544 | 3,246,772 | 1,880,663 | ||||||||||||||||||||||||
Eliminations | (540,075 | ) | (3,272,574 | ) | (3,568,065 | ) | (664,522 | ) | (1,562,199 | ) | (2,359,256 | ) | (471,255 | ) | (27,798 | ) | ||||||||||||||||
Retail propane and other retail propane related segment | 902,471 | 1,162,941 | 1,624,010 | 511,258 | 1,284,867 | 879,556 | 709,473 | 349,344 | ||||||||||||||||||||||||
Other | 6,004 | 13,675 | 16,201 | 5,892 | 121,278 | 102,028 | 75,700 | 30,810 | ||||||||||||||||||||||||
Total revenues | 3,911,513 | 7,498,686 | 9,293,367 | 2,349,342 | 6,792,037 | 7,859,096 | 6,168,798 | 2,346,957 | ||||||||||||||||||||||||
Gross margin | 1,648,233 | 1,761,442 | 2,355,287 | 675,688 | 1,713,831 | 1,290,780 | 787,283 | 365,533 | ||||||||||||||||||||||||
Depreciation and amortization | 239,626 | 200,922 | 274,372 | 75,406 | 191,383 | 129,636 | 105,751 | 56,242 | ||||||||||||||||||||||||
Operating income | 744,630 | 846,133 | 1,098,903 | 316,651 | 809,336 | 575,540 | 297,921 | 130,806 | ||||||||||||||||||||||||
Interest expense, net of interest capitalized | (341,050 | ) | (261,297 | ) | (357,541 | ) | (103,375 | ) | (279,986 | ) | (150,646 | ) | (101,061 | ) | (41,217 | ) | ||||||||||||||||
Gain on Energy Transfer Transactions | — | — | — | — | — | — | — | 395,253 | ||||||||||||||||||||||||
Income before income tax expense | 461,548 | 625,692 | 683,562 | 192,758 | 563,359 | 433,907 | 201,795 | 484,715 | ||||||||||||||||||||||||
Income tax expense | 5,773 | 6,600 | 3,808 | 9,949 | 11,391 | 23,015 | 4,397 | 2,792 | ||||||||||||||||||||||||
Net income attributable to noncontrolling interest | 152,893 | 266,614 | 304,710 | 90,132 | 232,608 | 303,752 | 162,242 | 37,869 | ||||||||||||||||||||||||
Net income attributable to partners | 302,882 | 352,478 | 375,044 | 92,677 | 319,360 | 107,140 | 146,746 | 450,217 |
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Four Months | ||||||||||||||||||||||||||||||||
Nine Months Ended | Year Ended | Ended | ||||||||||||||||||||||||||||||
September 30, | December 31, | December 31, | Years Ended August 31, | |||||||||||||||||||||||||||||
2009 | 2008 | 2008 | 2007 | 2007 | 2006 | 2005 | 2004 | |||||||||||||||||||||||||
Balance Sheet Data (at period end): | ||||||||||||||||||||||||||||||||
Current assets | 858,411 | 1,779,940 | 1,180,995 | 1,403,796 | 1,050,578 | 1,302,735 | 1,453,730 | 481,868 | ||||||||||||||||||||||||
Total assets | 11,684,508 | 11,267,924 | 11,069,902 | 9,462,094 | 8,183,089 | 5,924,141 | 4,905,672 | 2,865,191 | ||||||||||||||||||||||||
Current liabilities | 882,387 | 1,322,535 | 1,208,921 | 1,241,433 | 932,815 | 1,020,787 | 1,244,785 | 404,917 | ||||||||||||||||||||||||
Long-term debt, less current maturities | 7,740,135 | 7,181,710 | 7,190,357 | 5,870,106 | 5,198,676 | 3,205,646 | 2,275,965 | 1,071,158 | ||||||||||||||||||||||||
Total equity | 2,753,663 | 47,969 | 2,339,316 | 2,091,156 | 1,835,300 | 1,484,878 | 1,123,998 | 1,171,545 | ||||||||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||||||||||
Cash flow provided by operating activities | 721,421 | 908,837 | 1,143,720 | 208,635 | 1,006,320 | 502,928 | 155,272 | 161,486 | ||||||||||||||||||||||||
Cash flow used in investing activities | (1,225,719 | ) | (1,439,741 | ) | (2,015,585 | ) | (995,943 | ) | (2,158,090 | ) | (1,244,406 | ) | (1,131,117 | ) | (731,831 | ) | ||||||||||||||||
Cash flow provided by financing activities | 462,467 | 1,100,479 | 907,331 | 766,515 | 1,202,916 | 734,223 | 926,452 | 598,125 | ||||||||||||||||||||||||
Capital expenditures: | ||||||||||||||||||||||||||||||||
Maintenance (accrual basis) | 71,766 | 75,931 | 140,966 | 48,998 | 89,226 | 51,826 | 41,054 | 22,514 | ||||||||||||||||||||||||
Growth (accrual basis) | 534,696 | 1,532,458 | 1,921,679 | 604,371 | 998,075 | 677,861 | 155,405 | 87,174 | ||||||||||||||||||||||||
Acquisition | 6,244 | 62,002 | 84,783 | 337,092 | 90,695 | 586,185 | 1,131,844 | 622,929 |
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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• | Intrastate transportation and storage — Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary feeand/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued based on the published market prices as of the first of the month and sold at market prices. The HPL System also generates revenue from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies. The use of the Bammel storage reservoir allows ETP to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin, in addition to generating revenue from fee-based contracts to reserve firm storage capacity. | |
• | Interstate transportation — Revenue is primarily generated from fees earned from natural gas transportation services and operational gas sales. | |
• | Midstream — Revenue is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through our pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices. | |
• | Retail propane — Revenue is generated from the sale of propane and propane-related products and services. |
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Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | Change | ||||||||||
Equity in earnings of affiliates | $ | 370,195 | $ | 441,299 | $ | (71,104 | ) | |||||
Selling, general and administrative expenses | (3,608 | ) | (4,523 | ) | 915 | |||||||
Interest expense | (56,728 | ) | (69,527 | ) | 12,799 | |||||||
Losses on non-hedged interest rate derivatives | (7,954 | ) | (13,759 | ) | 5,805 | |||||||
Other, net | 329 | (993 | ) | 1,322 |
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Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | Change | ||||||||||
Revenues | $ | 3,911,513 | $ | 7,498,686 | $ | (3,587,173 | ) | |||||
Cost of products sold | 2,263,280 | 5,737,244 | (3,473,964 | ) | ||||||||
Gross margin | 1,648,233 | 1,761,442 | (113,209 | ) | ||||||||
Operating expenses | 517,337 | 573,606 | (56,269 | ) | ||||||||
Depreciation and amortization | 239,626 | 200,922 | 38,704 | |||||||||
Selling, general and administrative | 146,640 | 140,781 | 5,859 | |||||||||
Operating income | 744,630 | 846,133 | (101,503 | ) | ||||||||
Interest expense, net of interest capitalized | (341,050 | ) | (261,297 | ) | (79,753 | ) | ||||||
Equity in earnings (losses) of affiliates | 11,751 | (749 | ) | 12,500 | ||||||||
Gains (losses) on disposal of assets | (1,333 | ) | 1,584 | (2,917 | ) | |||||||
Gains (losses) on non-hedged interest rate derivatives | 24,373 | (13,610 | ) | 37,983 | ||||||||
Allowance for equity funds used during construction | 18,618 | 45,275 | (26,657 | ) | ||||||||
Other, net | 4,559 | 8,356 | (3,797 | ) | ||||||||
Income tax expense | (5,773 | ) | (6,600 | ) | 827 | |||||||
Net income | $ | 455,775 | $ | 619,092 | $ | (163,317 | ) | |||||
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Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | Change | ||||||||||
Intrastate transportation and storage | $ | 404,217 | $ | 547,931 | $ | (143,714 | ) | |||||
Interstate transportation | 101,755 | 91,414 | 10,341 | |||||||||
Midstream | 93,646 | 154,561 | (60,915 | ) | ||||||||
Retail propane and other retail propane related | 152,079 | 61,705 | 90,374 | |||||||||
Other | (4,803 | ) | (904 | ) | (3,899 | ) | ||||||
Unallocated selling, general and administrative expenses | (2,264 | ) | (8,574 | ) | 6,310 | |||||||
Operating income | $ | 744,630 | $ | 846,133 | $ | (101,503 | ) | |||||
Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | Change | ||||||||||
Natural gas MMBtu/d — transported | 12,769,022 | 10,515,132 | 2,253,890 | |||||||||
Natural gas MMBtu/d — sold | 879,861 | 1,556,524 | (676,663 | ) | ||||||||
Revenues | $ | 1,589,298 | $ | 4,862,641 | $ | (3,273,343 | ) | |||||
Cost of products sold | 895,433 | 3,965,931 | (3,070,498 | ) | ||||||||
Gross margin | 693,865 | 896,710 | (202,845 | ) | ||||||||
Operating expenses | 155,461 | 227,026 | (71,565 | ) | ||||||||
Depreciation and amortization | 84,288 | 66,502 | 17,786 | |||||||||
Selling, general and administrative | 49,899 | 55,251 | (5,352 | ) | ||||||||
Segment operating income | $ | 404,217 | $ | 547,931 | $ | (143,714 | ) | |||||
• | As mentioned above, ETP’s fuel retention revenues are directly impacted by changes in natural gas prices and volumes. Due to the increased transportation volumes discussed above, fuel retention margins increased approximately $32.0 million compared to the prior period. However, natural gas prices for retained fuel decreased from an average of $8.99/MMBtu during the nine months ended September 30, 2008 to $3.25/MMBtu during the nine months ended September 30, 2009 resulting in a decrease to the retention margin of $179.0 million. | |
• | ETP experienced a net decrease in storage margin of $87.5 million primarily due to a decrease in realized margin of $87.9 million as a result of a 24.7 Bcf decrease in natural gas sold between the periods from its Bammel storage facility. In addition, ETP experienced fluctuations related to its storage-related derivative activities that resulted in a net increase of $0.4 million. During the 2008 period and the first three months of 2009, ETP accounted for certain of its storage-related derivative instruments usingmark-to-market accounting with changes in the value of these financial derivative instruments being recorded directly in earnings. During the nine months ended September 30, 2008, ETP recognized unrealized gains of $23.1 million frommark-to-market adjustments and realized losses |
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of $5.7 million from the settlement of derivative contracts. During the three months ended March 31, 2009, ETP recognized $66.3 million in net gains frommark-to-market adjustments and the settlement of storage-related derivative contracts primarily due to expected natural gas withdrawals that were ultimately deferred. Beginning in April 2009, ETP elected fair value hedge accounting for certain storage-related transactions and recognized $3.5 million in realized gains from the settlement of derivative contracts and $2.1 million in unrealized gains from inventory fair value adjustments related to changes in the spot prices for natural gas and changes in value of the financial derivatives associated with storage during the nine months ended September 30, 2009. In addition, during the nine months ended September 30, 2009, ETP recognized $54.0 million in unrealized losses as a result of a non-cash lower of cost or market write-down of its natural gas inventory. |
• | Transportation fees increased approximately $84.8 million primarily due to increased volumes through ETP’s transportation pipelines. Overall volumes on ETP’s transportation pipelines were higher principally due to increased capacity of its pipeline system as a result of the completion of the Paris Loop, Maypearl to Malone pipeline, Carthage Loop, Southern Shale pipeline, Cleburne to Tolar pipeline and the Katy expansion during 2008 and 2009. | |
• | In addition to the above factors, ETP experienced a reduction in margin of $53.1 million as compared to the prior period principally due to the decrease in natural gas sold as a result of lower natural gas prices, lower west to east price differentials, and lower demand from industrial end users and local distribution companies. |
Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | Change | ||||||||||
Natural gas MMBtu/d — transported | 1,706,199 | 1,750,592 | (44,393 | ) | ||||||||
Natural gas MMBtu/d — sold | 19,481 | 13,094 | 6,387 | |||||||||
Revenues | $ | 203,349 | $ | 176,663 | $ | 26,686 | ||||||
Operating expenses | 46,427 | 39,128 | 7,299 | |||||||||
Depreciation and amortization | 36,017 | 28,204 | 7,813 | |||||||||
Selling, general and administrative | 19,150 | 17,917 | 1,233 | |||||||||
Segment operating income | $ | 101,755 | $ | 91,414 | $ | 10,341 | ||||||
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Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | Change | ||||||||||
Natural gas MMBtu/d — sold | 1,009,547 | 1,361,295 | (351,748 | ) | ||||||||
NGLs Bbls/d — sold | 40,345 | 27,618 | 12,727 | |||||||||
Revenues | $ | 1,750,466 | $ | 4,555,340 | $ | (2,804,874 | ) | |||||
Cost of products sold | 1,510,030 | 4,271,788 | (2,761,758 | ) | ||||||||
Gross margin | 240,436 | 283,552 | (43,116 | ) | ||||||||
Operating expenses | 50,858 | 50,792 | 66 | |||||||||
Depreciation and amortization | 54,749 | 46,960 | 7,789 | |||||||||
Selling, general and administrative | 41,183 | 31,239 | 9,944 | |||||||||
Segment operating income | $ | 93,646 | $ | 154,561 | $ | (60,915 | ) | |||||
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Nine Months Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | Change | ||||||||||
Retail propane gallons (in thousands) | 398,202 | 422,109 | (23,907 | ) | ||||||||
Retail propane revenues | $ | 829,901 | $ | 1,086,417 | $ | (256,516 | ) | |||||
Other retail propane related revenues | 72,570 | 76,524 | (3,954 | ) | ||||||||
Retail propane cost of products sold | 378,524 | 744,316 | (365,792 | ) | ||||||||
Other retail propane related cost of products sold | 14,495 | 17,099 | (2,604 | ) | ||||||||
Gross margin | 509,452 | 401,526 | 107,926 | |||||||||
Operating expenses | 259,768 | 253,193 | 6,575 | |||||||||
Depreciation and amortization | 63,477 | 58,828 | 4,649 | |||||||||
Selling, general and administrative | 34,128 | 27,800 | 6,328 | |||||||||
Segment operating income | $ | 152,079 | $ | 61,705 | $ | 90,374 | ||||||
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Year Ended | Year Ended | |||||||||||
December 31, 2008 | August 31, 2007 | Change | ||||||||||
Equity in earnings of affiliates | $ | 551,835 | $ | 435,247 | $ | 116,588 | �� | |||||
Selling, general and administrative expenses | 6,453 | 8,496 | (2,043 | ) | ||||||||
Interest expense | 91,822 | 104,405 | (12,583 | ) | ||||||||
Losses on non-hedged interest rate derivatives | (77,435 | ) | (1,952 | ) | (75,483 | ) | ||||||
Other, net | (1,056 | ) | (405 | ) | (651 | ) |
Year Ended | Year Ended | |||||||||||
December 31, 2008 | August 31, 2007 | Change | ||||||||||
Revenues | $ | 9,293,367 | $ | 6,792,037 | $ | 2,501,330 | ||||||
Cost of products sold | 6,938,080 | 5,078,206 | 1,859,874 | |||||||||
Gross margin | 2,355,287 | 1,713,831 | 641,456 | |||||||||
Operating expenses | 781,831 | 559,600 | 222,231 | |||||||||
Depreciation and amortization | 274,372 | 191,383 | 82,989 | |||||||||
Selling, general and administrative | 200,181 | 153,512 | 46,669 | |||||||||
Operating income | 1,098,903 | 809,336 | 289,567 | |||||||||
Interest expense, net of interest capitalized | (357,541 | ) | (279,986 | ) | (77,555 | ) | ||||||
Equity in earnings (losses) of affiliates | (165 | ) | 5,161 | (5,326 | ) | |||||||
Gain (loss) on disposal of assets | (1,303 | ) | (6,310 | ) | 5,007 | |||||||
Gains (losses) on non-hedged interest rate derivatives | (128,423 | ) | 29,081 | (157,504 | ) | |||||||
Allowance for equity funds used during construction | 63,976 | 4,948 | 59,028 | |||||||||
Other, net | 8,115 | 1,129 | 6,986 | |||||||||
Income tax expense | (3,808 | ) | (11,391 | ) | 7,583 | |||||||
Net income | $ | 679,754 | $ | 551,968 | $ | 127,786 | ||||||
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Year Ended | Year Ended | |||||||||||
December 31, 2008 | August 31, 2007 | Change | ||||||||||
Intrastate transportation and storage | $ | 710,070 | $ | 479,820 | $ | 230,250 | ||||||
Interstate transportation | 124,676 | 95,650 | 29,026 | |||||||||
Midstream | 162,471 | 119,233 | 43,238 | |||||||||
Retail propane | 114,564 | 124,263 | (9,699 | ) | ||||||||
Other | (2,032 | ) | 1,735 | (3,767 | ) | |||||||
Unallocated selling, general and administrative expenses | (10,846 | ) | (11,365 | ) | 519 | |||||||
Operating income | $ | 1,098,903 | $ | 809,336 | $ | 289,567 | ||||||
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Year Ended | Year Ended | |||||||||||
December 31, | August 31, | |||||||||||
2008 | 2007 | Change | ||||||||||
Natural gas MMBtu/d — transported | 11,187,327 | 6,124,423 | 5,062,904 | |||||||||
Natural gas MMBtu/d — sold | 1,389,781 | 1,400,753 | (10,972 | ) | ||||||||
Revenues | $ | 5,634,604 | $ | 3,915,932 | $ | 1,718,672 | ||||||
Cost of products sold | 4,467,552 | 3,137,712 | 1,329,840 | |||||||||
Gross margin | 1,167,052 | 778,220 | 388,832 | |||||||||
Operating expenses | 287,515 | 181,133 | 106,382 | |||||||||
Depreciation and amortization | 92,979 | 64,423 | 28,556 | |||||||||
Selling, general and administrative | 76,488 | 52,844 | 23,644 | |||||||||
Segment operating income | $ | 710,070 | $ | 479,820 | $ | 230,250 | ||||||
• | Overall volumes on ETP’s transportation pipelines were higher due to increased demand to transport natural gas out of the Barnett Shale and Bossier Sands producing regions, increased demand for natural gas used by electricity-producing power plants connected to its assets and the completion of several pipeline expansion projects. The increase in transport volumes were also due to favorable market conditions between the Waha and Katy/Houston Ship Channel market hubs resulting in higher volumes and higher average rates on ETP’s intrastate pipeline systems. Transportation fees increased approximately $281.3 million for the year ended December 31, 2008 as compared to the year ended August 31, 2007. Fuel retention revenue increased approximately $130.3 million due to increased volumes transported through our transportation pipelines. | |
• | Higher natural gas prices resulting in additional retention margin of $35.8 million. ETP’s average natural gas prices for retained fuel increased to an average of $9.66/MMBtu during the year ended December 31, 2008 from an average of $6.69/MMBtu during the year ended August 31, 2007. | |
• | A decrease in natural gas storage-related margin of $51.3 million. Realized margin, comprised of both margin on the withdrawal and sale of natural gas and realized gains on derivative instruments related to ETP’s storage operations, decreased by $79.2 million for the year ended December 31, 2008 compared to the year ended August 31, 2007. During the year ended December 31, 2008, there were physical sales of 39.5 Bcf of natural gas from our Bammel storage facility compared to 67.6 Bcf in the 2007 period. In addition, between the comparable twelve month periods, there was an increase of $13.1 million in storage fees, primarily due to a new contract that commenced on April 1, 2007 at ETP’s Bammel storage facility. Furthermore, ETP recognized unrealizedmark-to-market gains related to its storage operations (which represent the change in the fair value of derivative instruments not designated as hedges for accounting purposes) of $68.2 million during the year ended December 31, 2008 compared to $5.6 million during the year ended August 31, 2007. The amount that ETP will ultimately realize, however, is subject to change as commodity prices change in future months and the underlying physical transaction occurs. In addition, ETP recognized a netlower-of-cost-or-market adjustment of $47.8 million related to natural gas stored in its Bammel storage facility during the year ended December 31, 2008. |
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Year Ended | Year Ended | |||||||||||
December 31, | August 31, | |||||||||||
2008 | 2007 | Change | ||||||||||
Natural gas MMBtu/d — transported | 1,777,097 | 1,802,109 | (25,012 | ) | ||||||||
Natural gas MMBtu/d — sold | 15,162 | 19,680 | (4,518 | ) | ||||||||
Revenues | $ | 244,224 | $ | 178,663 | $ | 65,561 | ||||||
Operating expenses | 56,906 | 36,295 | 20,611 | |||||||||
Depreciation and amortization | 37,790 | 27,972 | 9,818 | |||||||||
Selling, general and administrative | 24,852 | 18,746 | 6,106 | |||||||||
Segment operating income | $ | 124,676 | $ | 95,650 | $ | 29,026 | ||||||
Year Ended | Year Ended | |||||||||||
December 31, | August 31, | |||||||||||
2008 | 2007 | Change | ||||||||||
Natural gas MMBtu/d — sold | 1,269,724 | 941,140 | 328,584 | |||||||||
NGLs Bbls/d — sold | 25,939 | 17,907 | 8,032 | |||||||||
Revenues | $ | 5,342,393 | $ | 2,853,496 | $ | 2,488,897 | ||||||
Cost of products sold | 4,986,495 | 2,632,187 | 2,354,308 | |||||||||
Gross margin | 355,898 | 221,309 | 134,589 | |||||||||
Operating expenses | 82,872 | 39,148 | 43,724 | |||||||||
Depreciation and amortization | 63,287 | 27,331 | 35,956 | |||||||||
Selling, general and administrative | 47,268 | 35,597 | 11,671 | |||||||||
Segment operating income | $ | 162,471 | $ | 119,233 | $ | 43,238 | ||||||
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• | An increase in fee-based revenue and processing margin of $82.9 million and $55.6 million, respectively, from ETP’s gathering and processing assets (other than its Canyon Gathering System). The increase was due to incremental volumes from the expansion of the Godley plant since placing it into service as well as favorable market conditions to process and extract NGLs. | |
• | Incremental margin of $25.1 million due to the acquisition of the Canyon Gathering System in October 2007. | |
• | A net decrease of $24.7 million in margin from ETP’s trading and marketing activities. Net realized and unrealized trading losses were $26.2 million for the year ended December 31, 2008, compared to a net gain of $2.2 million for the year ended August 31, 2007. The loss for the year ended December 31, 2008 was due to unfavorable market conditions. Other marketing activities resulted in a margin of $23.3 million for the year ended December 31, 2008 compared to $19.6 million for the year ended August 31, 2007. |
Year Ended | Year Ended | |||||||||||
December 31, | August 31, | |||||||||||
2008 | 2007 | Change | ||||||||||
Retail propane gallons sold (in thousands) | 601,134 | 604,269 | (3,135 | ) | ||||||||
Retail propane revenues | $ | 1,514,599 | $ | 1,179,073 | $ | 335,526 | ||||||
Other retail propane related revenues | 109,411 | 105,794 | 3,617 | |||||||||
Retail propane cost of products sold | 1,014,068 | 734,204 | 279,864 | |||||||||
Other retail propane related cost of products sold | 24,654 | 25,430 | (776 | ) | ||||||||
Gross margin | 585,288 | 525,233 | 60,055 | |||||||||
Operating expenses | 350,280 | 297,469 | 52,811 | |||||||||
Depreciation and amortization | 79,717 | 70,833 | 8,884 | |||||||||
Selling, general and administrative | 40,727 | 32,668 | 8,059 | |||||||||
Segment operating income | $ | 114,564 | $ | 124,263 | $ | (9,699 | ) | |||||
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Four Months Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change | ||||||||||
Equity in earnings of affiliates | $ | 168,547 | $ | 107,586 | $ | 60,961 | ||||||
Selling, general and administrative expenses | 2,875 | 3,131 | (256 | ) | ||||||||
Interest expense | 37,071 | 28,026 | 9,045 | |||||||||
Losses on non-hedged interest rate derivatives | (27,670 | ) | — | (27,670 | ) | |||||||
Other, net | (8,128 | ) | 252 | (8,380 | ) |
Four Months Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change | ||||||||||
Revenues | $ | 2,349,342 | $ | 2,162,466 | $ | 186,876 | ||||||
Cost of products sold | 1,673,654 | 1,689,843 | (16,189 | ) | ||||||||
Gross margin | 675,688 | 472,623 | 203,065 | |||||||||
Operating expenses | 221,757 | 173,365 | 48,392 | |||||||||
Depreciation and amortization | 75,406 | 52,840 | 22,566 | |||||||||
Selling, general and administrative | 61,874 | 43,602 | 18,272 | |||||||||
Operating income | 316,651 | 202,816 | 113,835 | |||||||||
Interest expense, net of interest capitalized | (103,375 | ) | (82,979 | ) | (20,396 | ) | ||||||
Equity in earnings (losses) of affiliates | (94 | ) | 4,743 | (4,837 | ) | |||||||
Gain (loss) on disposal of assets | 14,310 | 2,212 | 12,098 | |||||||||
Other, net | (34,734 | ) | 2,248 | (36,982 | ) | |||||||
Income tax expense | (9,949 | ) | (2,155 | ) | (7,794 | ) | ||||||
Net income | $ | 182,809 | $ | 126,885 | $ | 55,924 | ||||||
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Four Months Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change | ||||||||||
Intrastate transportation and storage | $ | 169,361 | $ | 109,262 | $ | 60,099 | ||||||
Interstate transportation | 29,657 | 11,854 | 17,803 | |||||||||
Midstream | 71,853 | 40,421 | 31,432 | |||||||||
Retail propane | 46,747 | 49,841 | (3,094 | ) | ||||||||
Other | (796 | ) | 528 | (1,324 | ) | |||||||
Unallocated selling, general and administrative expenses | (171 | ) | (9,090 | ) | 8,919 | |||||||
Operating income | $ | 316,651 | $ | 202,816 | $ | 113,835 | ||||||
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Four Months Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change | ||||||||||
Natural gas MMBtu/d — transported | 8,787,387 | 4,889,029 | 3,898,358 | |||||||||
Natural gas MMBtu/d — sold | 1,259,566 | 1,379,721 | (120,155 | ) | ||||||||
Revenues | $ | 1,254,401 | $ | 1,195,871 | $ | 58,530 | ||||||
Cost of products sold | 964,568 | 994,511 | (29,943 | ) | ||||||||
Gross margin | 289,833 | 201,360 | 88,473 | |||||||||
Operating expenses | 76,428 | 56,452 | 19,976 | |||||||||
Depreciation and amortization | 23,429 | 19,020 | 4,409 | |||||||||
Selling, general and administrative | 20,615 | 16,626 | 3,989 | |||||||||
Segment operating income | $ | 169,361 | $ | 109,262 | $ | 60,099 | ||||||
• | Transported natural gas volumes increased principally due to the increased volumes experienced on the ET Fuel and East Texas Pipeline systems as a result of the completion of the Cleburne to Carthage Pipeline, increased demand to transport natural gas out of the Barnett Shale and Bossier Sands producing regions, and the continued effort to secure long-term shipper contracts. | |
• | Natural gas sales volumes on the HPL System decreased primarily due to the new CenterPoint contract that commenced on April 1, 2007. Under the previous contract, ETP sold and delivered natural gas to CenterPoint for a bundled price. Under the terms of the new agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas capacity in ETP’s Bammel storage facility. | |
• | Transportation fees increased approximately $53.2 million. Retention revenue increased approximately $29.7 million due to increased volumes transported through ETP’s transportation pipelines; | |
• | Increase in processing margin of $8.6 million from ETP’s HPL system. Processing margins generated from ETP’s HPL system benefited from favorable market conditions to process and extract NGLs during the four months ended December 31, 2007; and | |
• | Net decrease in storage margins of $9.4 million. During the four months ended December 31, 2006, ETP recognized approximately $27.0 million of margin on 13 Bcf of gas sold from its Bammel storage facility. Due to market conditions, there were no withdrawals in the same period in 2007; however, ETP did recognize $9.2 million in gains from the discontinuation of hedge accounting resulting from its determination that originally forecasted sales of natural gas from its Bammel storage facility were no longer probable to occur by the specified time period, or within an additional two-month time period thereafter. In addition, fee-based storage revenues increased $8.4 million primarily due to the new Centerpoint contract which commenced on April 1, 2007 in which Centerpoint contracted for 10 Bcf of working gas capacity in ETP’s Bammel storage facility. |
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Four Months Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change | ||||||||||
Natural gas MMBtu/d — transported | 1,708,477 | 1,822,065 | (113,588 | ) | ||||||||
Natural gas MMBtu/d — sold | 13,663 | 14,104 | (441 | ) | ||||||||
Revenues | $ | 76,000 | $ | 19,003 | $ | 56,997 | ||||||
Operating expenses | 23,922 | 1,396 | 22,526 | |||||||||
Depreciation and amortization | 12,305 | 3,191 | 9,114 | |||||||||
Selling, general and administrative | 10,116 | 2,562 | 7,554 | |||||||||
Segment operating income | $ | 29,657 | $ | 11,854 | $ | 17,803 | ||||||
Four Months Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change | ||||||||||
Natural gas MMBtu/d — sold | 1,090,090 | 968,016 | 122,074 | |||||||||
NGLs Bbls/d — sold | 25,389 | 12,458 | 12,931 | |||||||||
Revenues | $ | 1,166,313 | $ | 905,392 | $ | 260,921 | ||||||
Cost of products sold | 1,043,191 | 839,561 | 203,630 | |||||||||
Gross margin | 123,122 | 65,831 | 57,291 | |||||||||
Operating expenses | 17,633 | 11,710 | 5,923 | |||||||||
Depreciation and amortization | 14,943 | 7,748 | 7,195 | |||||||||
Selling, general and administrative | 18,693 | 5,952 | 12,741 | |||||||||
Segment operating income | $ | 71,853 | $ | 40,421 | $ | 31,432 | ||||||
• | Increases in processing margin of $37.6 million and fee-based revenue of $17.9 million from ETP’s gathering and processing assets. The increase was due to incremental volumes from the completion of ETP’s Godley plant in October 2006, the continued expansion of the plant since placing it into service, and the acquisition of three gathering systems during the first six months of the 2007 fiscal year. In addition, ETP’s midstream assets benefited from favorable market conditions to process and extract NGLs during the four months ended December 31, 2007. Due to changes in the contract structures at ETP’s Godley plant, arrangements for which ETP had been recognizing the increased margin from favorable conditions converted to long-term fee-based contracts in November 2007. As such, ETP expects margin from processing at its Godley plant to be more predictable and less sensitive to commodity price volatility. As of December 31, 2007, the Godley plant had approximately500 MMcf/d of cryoprocessing capacity and100 MMcf/d of dew point processing capacity. | |
• | Increase in non-trading margin from ETP’s marketing activities of $1.0 million as market conditions resulted in higher sales volumes conducted by ETP’s producer services’ operations. | |
• | Decrease in net trading revenues of $5.2 million. |
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• | Canyon Gathering System — The acquisition of the Canyon Gathering System on October 5, 2007 contributed approximately $5.6 million of incremental margin for the four months ended December 31, 2007. |
Four Months Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change | ||||||||||
Retail propane gallons sold (in thousands) | 205,311 | 214,623 | (9,312 | ) | ||||||||
Retail propane revenues | $ | 471,494 | $ | 409,821 | $ | 61,673 | ||||||
Other retail propane related revenues | 39,764 | 40,020 | (256 | ) | ||||||||
Retail propane cost of products sold | 315,698 | 256,994 | 58,704 | |||||||||
Other retail propane related cost of products sold | 9,460 | 10,344 | (884 | ) | ||||||||
Gross margin | 186,100 | 182,503 | 3,597 | |||||||||
Operating expenses | 102,537 | 101,508 | 1,029 | |||||||||
Depreciation and amortization | 24,537 | 22,520 | 2,017 | |||||||||
Selling, general and administrative | 12,279 | 8,634 | 3,645 | |||||||||
Segment operating income | $ | 46,747 | $ | 49,841 | $ | (3,094 | ) | |||||
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• | growth capital expenditures for its midstream and intrastate transportation and storage segments primarily for the construction of new pipelines and compression, for which ETP expects to spend between $60 million and $80 million in 2010; | |
• | growth capital expenditures for its interstate transportation segment, excluding capital contributions to the MEP and FEP projects as discussed below, for the construction of new pipelines and pipeline expansions for its interstate operations, for which ETP expects to spend between $880 million and $900 million in 2010; | |
• | capital contributions to MEP and FEP as follows: |
• | With respect to MEP, capital expenditures have been funded under the MEP Facility and through capital contributions from ETP and KMP, our joint venture partner. In September 2009, MEP issued $800 million of senior unsecured notes and used the proceeds to reduce amounts outstanding under the MEP Facility. ETP made a contribution of $200 million to MEP during October 2009 and does not expect any additional capital contributions during the remainder of 2009. The October 2009 contribution was used to further reduce amounts outstanding under the MEP Facility. Subsequent to these repayments, the commitment amount under the MEP Facility was reduced from $1.4 billion to |
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$275 million. Availability on the MEP Facility will be used to fund capital expenditures associated with MEP’s expansion projects that are expected to be completed by December 2010. For 2010, ETP expects its capital contributions to MEP to be between $80 million and $90 million. |
• | With respect to FEP, in November 2009, it entered into a senior unsecured revolving credit facility, which is severally guaranteed by ETP and KMP. ETP does not expect to make additional capital contributions to FEP and has been reimbursed for its prior capital contributions, which totaled $70.0 million through September 30, 2009. |
• | growth capital expenditures for its retail propane segment of between $30 million and $40 million in 2010; | |
• | maintenance capital expenditures of between $120 million and $130 million in 2010; and | |
• | acquisitions, including the potential acquisition of new pipeline systems and propane operations. |
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• | 6,900,000 common units in January 2009 at $34.05 per unit, resulting in net proceeds of approximately $225.9 million; | |
• | 9,775,000 common units in April 2009 at $37.55 per unit, resulting in net proceeds of approximately $352.4 million; | |
• | 6,900,000 common units in October 2009 at $41.27 per unit, resulting in net proceeds of approximately $275.3 million; and | |
• | 9,775,000 common units in January 2010 at $44.72 per unit, resulting in net proceeds of approximately $422.9 million. |
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September 30, | December 31, | |||||||
2009 | 2008 | |||||||
ETE Indebtedness | ||||||||
Senior Secured Term Loan Facility | $ | 1,450,000 | $ | 1,450,000 | ||||
Senior Secured Revolving Credit Facility | 123,923 | 121,642 | ||||||
ETP Indebtedness | ||||||||
ETP Senior Notes | 5,050,000 | 4,050,000 | ||||||
Transwestern Senior Notes | 520,000 | 520,000 | ||||||
HOLP Senior Secured Notes | 144,912 | 181,410 | ||||||
Revolving Credit Facilities | 483,265 | 912,000 | ||||||
Other long-term debt | 27,159 | 14,014 | ||||||
Unamortized discounts | (13,009 | ) | (13,477 | ) | ||||
Total Debt | $ | 7,786,250 | $ | 7,235,589 | ||||
Payments Due by Period | ||||||||||||||||||||
Less than | More than | |||||||||||||||||||
Contractual Obligations | Total | 1 Year | 1-3 Years | 3-5 Years | 5 Years | |||||||||||||||
Long-term debt(a) | $ | 7,235,589 | $ | 45,232 | $ | 206,862 | $ | 3,147,308 | $ | 3,836,187 | ||||||||||
Interest on fixed rate long-term debt(b) | 4,097,248 | 307,958 | 637,148 | 604,179 | 2,547,963 | |||||||||||||||
Payments on derivatives | 264,142 | 142,432 | 88,558 | 23,684 | 9,468 | |||||||||||||||
Purchase commitments(c) | 259,483 | 256,901 | 2,582 | — | — | |||||||||||||||
Operating lease obligations | 314,648 | 21,041 | 38,498 | 30,999 | 224,110 | |||||||||||||||
Totals | $ | 12,171,110 | $ | 773,564 | $ | 973,648 | $ | 3,806,170 | $ | 6,617,728 | ||||||||||
(a) | See “Description of Other Indebtedness.” |
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(b) | Fixed rate interest on long-term debt includes the amount of interest due on our fixed rate long-term debt. These amounts do not include interest on variable rate debt obligations, which include our and ETP’s revolving credit facilities and revolving credit facility swingline loan options. As of December 31, 2008, variable rate interest on our and ETP’s outstanding balance of variable rate debt of $2.48 billion would be $90.3 million on an annual basis. | |
(c) | We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for propane and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2008 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated. |
Nine Months | Four Months | |||||||||||||||||||
Ended | Year Ended | Ended | Year Ended | |||||||||||||||||
September 30, | December 31, | December 31, | August 31, | |||||||||||||||||
2009 | 2008 | 2008 | 2007 | 2007 | ||||||||||||||||
Limited Partner Interests | $ | 167,580 | $ | 166,018 | $ | 221,878 | $ | 70,313 | $ | 199,221 | ||||||||||
General Partner Interest | 14,588 | 12,740 | 17,322 | 5,110 | 13,676 | |||||||||||||||
Incentive Distribution Rights | 255,808 | 219,298 | 298,575 | 85,775 | 222,353 | |||||||||||||||
Total distributions received from ETP(1) | $ | 437,976 | $ | 398,056 | $ | 537,775 | $ | 161,198 | $ | 435,250 | ||||||||||
(1) | Represents cash distributions received in respect of each of the quarters included within the period, including distributions paid in respect of the last quarter of such period after the end of such quarter and excluding distributions paid during the first quarter of such period in respect of the prior quarter. |
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Record Date | Payment Date | Amount per Unit | ||||||
Calendar Year Ended December 31, 2009 | ||||||||
November 9, 2009 | November 19, 2009 | $ | 0.5350 | |||||
August 7, 2009 | August 19, 2009 | 0.5350 | ||||||
May 8, 2009 | May 19, 2009 | 0.5250 | ||||||
February 6, 2009 | February 19, 2009 | 0.5100 | ||||||
Calendar Year Ended December 31, 2008 | ||||||||
November 10, 2008 | November 19, 2008 | $ | 0.4800 | |||||
August 7, 2008 | August 19, 2008 | 0.4800 | ||||||
May 5, 2008 | May 19, 2008 | 0.4400 | ||||||
February 1, 2008(1) | February 19, 2008 | 0.5500 | ||||||
Transition Period Ended December 31, 2007 | ||||||||
October 5, 2007 | October 19, 2007 | $ | 0.3900 | |||||
Fiscal Year Ended August 31, 2007 | ||||||||
July 2, 2007 | July 19, 2007 | $ | 0.3725 | |||||
April 9, 2007 | April 16, 2007 | 0.3560 | ||||||
January 4, 2007 | January 19, 2007 | 0.3400 | ||||||
October 5, 2006 | October 19, 2006 | 0.3125 |
(1) | One-time four-month distribution — On January 18, 2008 our Board of Directors approved the management recommendation for a one-time four-month distribution for our unitholders to complete the conversion to a calendar year end from the previous August 31 fiscal year end. Our distribution amount related to the four months ended December 31, 2007 was $0.55 per common unit, representing a distribution of $0.41 per unit for the three-month period and $0.14 per unit for the additional month. This distribution was paid on February 19, 2008 to our unitholders of record as of the close of business on February 1, 2008. |
Record Date | Payment Date | Amount per Unit | ||||||
Calendar Year Ended December 31, 2009 | ||||||||
November 9, 2009 | November 16, 2009 | $ | 0.89375 | |||||
August 7, 2009 | August 14, 2009 | 0.89375 | ||||||
May 8, 2009 | May 15, 2009 | 0.89375 | ||||||
February 6, 2009 | February 13, 2009 | 0.89375 | ||||||
Calendar Year Ended December 31, 2008 | ||||||||
November 10, 2008 | November 14, 2008 | $ | 0.89375 | |||||
August 7, 2008 | August 14, 2008 | 0.89375 | ||||||
May 5, 2008 | May 15, 2008 | 0.86875 | ||||||
February 1, 2008(1) | February 14, 2008 | 1.12500 | ||||||
Transition Period Ended December 31, 2007 | ||||||||
October 5, 2007 | October 15, 2007 | $ | 0.82500 | |||||
Fiscal Year Ended August 31, 2007 | ||||||||
July 2, 2007 | July 19, 2007 | $ | 0.80625 | |||||
April 6, 2007 | April 13, 2007 | 0.78750 | ||||||
January 4, 2007 | January 15, 2007 | 0.76875 | ||||||
October 5, 2006 | October 16, 2006 | 0.75000 |
(1) | One-time four-month distribution — On January 18, 2008 the Board of Directors of ETP GP approved the management recommendation for a one-time four-month distribution for ETP unitholders to complete the conversion to a calendar year end from the previous August 31 fiscal year end. ETP’s distribution amount related to the four months ended December 31, 2007 was $1.125 per common unit, representing a distribution of $0.84375 per unit for the three-month period and $0.28125 per unit for the additional month. This distribution was paid on February 14, 2008 to ETP’s unitholders of record as of the close of business on February 1, 2008. |
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• | Acquisition costs are generally expensed as incurred; | |
• | Noncontrolling interests (previously referred to as “minority interests”) are valued at fair value at the acquisition date; | |
• | In-process research and development is recorded at fair value as an indefinite-lived intangible asset at the acquisition date; |
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• | Restructuring costs associated with a business combination are generally expensed subsequent to the acquisition date; and | |
• | Changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date are recorded in income taxes. |
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Fair Value | ||||||||||||||||
Notional | Asset | |||||||||||||||
Commodity | Volume | Maturity | (Liability) | |||||||||||||
(in thousands) | ||||||||||||||||
Mark to Market Derivatives | ||||||||||||||||
Basis Swaps IFERC/NYMEX (MMBtu) | Natural Gas | 78,932,500 | 2009-2011 | $ | 16,291 | |||||||||||
Swing Swaps IFERC (MMBtu) | Natural Gas | (53,500,000 | ) | 2009-2010 | 3,389 | |||||||||||
Fixed Swaps/Futures (MMBtu) | Natural Gas | (3,755,000 | ) | 2009-2011 | 3,527 | |||||||||||
Forwards/Swaps (Gallons) | Propane/Ethane | 11,718,000 | 2009-2010 | 2,447 | ||||||||||||
Fair Value Hedging Derivatives | ||||||||||||||||
Basis Swaps IFERC/NYMEX (MMBtu) | Natural Gas | (31,095,000 | ) | 2009-2010 | $ | (6,235 | ) | |||||||||
Fixed Swaps/Futures (MMBtu) | Natural Gas | (31,967,500 | ) | 2009-2010 | (7,341 | ) | ||||||||||
Cash Flow Hedging Derivatives | ||||||||||||||||
Basis Swaps IFERC/NYMEX (MMBtu) | Natural Gas | (16,830,000 | ) | 2009-2010 | $ | (390 | ) | |||||||||
Fixed Swaps/Futures (MMBtu) | Natural Gas | (27,625,000 | ) | 2009-2010 | (18,675 | ) | ||||||||||
Forwards/Swaps (Gallons) | Propane/Ethane | 28,518,000 | 2009-2010 | 4,312 |
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Fair Value | Effect of | |||||||||||||||
Notional | Asset | Hypothetical | ||||||||||||||
Commodity | Volume | (Liability) | 10% Change | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Mark to Market Derivatives | ||||||||||||||||
Basis Swaps IFERC/NYMEX (MMBtu) | Natural Gas | 78,932,500 | $ | 16,291 | $ | 2,887 | ||||||||||
Swing Swaps IFERC (MMBtu) | Natural Gas | (53,500,000 | ) | 3,389 | 884 | |||||||||||
Fixed Swaps/Futures (MMBtu) | Natural Gas | (3,755,000 | ) | 3,527 | 2,931 | |||||||||||
Forwards/Swaps (Gallons) | Propane/Ethane | 11,718,000 | 2,447 | 1,120 | ||||||||||||
Fair Value Hedging Derivatives | ||||||||||||||||
Basis Swaps IFERC/NYMEX (MMBtu) | Natural Gas | (31,095,000 | ) | $ | (6,235 | ) | $ | 411 | ||||||||
Fixed Swaps/Futures (MMBtu) | Natural Gas | (31,967,500 | ) | (7,341 | ) | 16,286 | ||||||||||
Cash Flow Hedging Derivatives | ||||||||||||||||
Basis Swaps IFERC/NYMEX (MMBtu) | Natural Gas | (16,830,000 | ) | $ | (390 | ) | $ | 267 | ||||||||
Fixed Swaps/Futures (MMBtu) | Natural Gas | (27,625,000 | ) | (18,675 | ) | 16,459 | ||||||||||
Forwards/Swaps (Gallons) | Propane/Ethane | 28,518,000 | 4,312 | 2,724 |
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• | Natural gas operations, consisting of the following segments: |
• | natural gas midstream and intrastate transportation and storage through La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company, or ETC OLP; and | |
• | interstate natural gas transportation services through ET Interstate, the parent company of Transwestern and ETC MEP. |
• | Retail propane through HOLP and Titan. |
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• | Capacity of 5.2 Bcf/d | |
• | 2,570 miles of natural gas pipeline | |
• | 2 storage facilities with 12.4 Bcf of total working gas capacity |
• | Capacity of 1.2 Bcf/d | |
• | 600 miles of natural gas pipeline | |
• | Connects Waha to Katy market hubs |
• | Capacity of 5.5 Bcf/d | |
• | 4,300 miles of natural gas pipeline | |
• | Bammel storage facility with 62 Bcf of total working gas capacity |
• | Capacity of 2.4 Bcf/d | |
• | 370 miles of natural gas pipeline |
• | Capacity of 2.1 Bcf/d | |
• | 2,700 miles of interstate natural gas pipeline | |
• | Phoenix lateral pipeline — 260 miles of36-inch and42-inch diameter pipeline with capacity of500 MMcf/d was completed in February 2009 |
• | Current capacity of 1.4 Bcf/d on zone 1 and 1.0 Bcf/d on zone 2 | |
• | Planned capacity expansion to 1.8 Bcf/d on zone 1 and 1.2 Bcf/d on zone 2 by July 2010 | |
• | 500 miles of interstate natural gas pipeline | |
• | 50/50 joint venture with KMP |
• | Initial planned capacity of 2.0 Bcf/d (expected to be in service in the fourth quarter of 2010) | |
• | 187 miles of interstate natural gas pipeline | |
• | 50/50 joint venture with KMP |
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• | Initial planned capacity of 2.0 Bcf/d (expected to be in service in the first half of 2011) | |
• | 178 miles of interstate natural gas pipeline |
• | 5,200 miles of natural gas pipeline | |
• | 1 natural gas processing plant (the La Grange plant) with aggregate capacity of240 MMcf/d | |
• | 11 natural gas treating facilities with aggregate capacity of 1.3 Bcf/d | |
• | 4 natural gas conditioning facilities with aggregate capacity of670 MMcf/d |
• | 160 miles of natural gas pipeline | |
• | 1 natural gas processing plant (the Godley plant) with aggregate capacity of500 MMcf/d | |
• | 1 natural gas conditioning facility with capacity of100 MMcf/d |
• | 1,390 miles of natural gas pipeline | |
• | 6 natural gas conditioning facilities with aggregate capacity of90 MMcf/d |
• | The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,570 miles of intrastate natural gas pipeline and related natural gas storage facilities. With approximately 460 receiptand/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, |
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the ET Fuel System is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in east Texas, the three major natural gas trading centers in Texas. The ET Fuel System has total system throughput capacity of approximately5.2 Bcf/d. |
• | The Oasis pipeline is primarily a36-inch diameter,600-mile intrastate natural gas pipeline that directly connects the Waha Hub to the Katy Hub. It has bi-directional capability with approximately 1.2 Bcf/d of throughput capacity movingwest-to-east and greater than750 MMcf/d of throughput capacity movingeast-to-west. The Oasis pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers. |
• | providing ETP with the ability to bypass the La Grange processing plant when processing margins are unfavorable; | |
• | providing access for natural gas on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines; and | |
• | allowing ETP to bypass its treating facilities on the Southeast Texas System and blend untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications. |
• | The HPL System is comprised of approximately 4,300 miles of intrastate natural gas pipeline with an aggregate capacity of 5.5 Bcf/d, the underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast of Texas, east Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System also includes 32 miles of the Cleburne to Carthage pipeline from ETP’s Texoma pipeline interconnect to the Carthage Hub. The HPL System is well situated to gather gas in many of the major gas producing areas in Texas and has a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contributes to ETP’s overall ability to play an important role in the Texas natural gas markets. The HPL System is also well positioned to capitalize upon off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, and ETP’s Bammel storage facility. |
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• | The East Texas pipeline is a370-mile intrastate natural gas pipeline that connects three treating facilities, one of which ETP owns, with ETP’s Southeast Texas System. This pipeline was the first phase of a multi-phased project that increased service to producers in East and North Central Texas and provided access to the Katy Hub. |
• | The Transwestern pipeline is an open-access natural gas interstate pipeline extending from the gas producing regions of West Texas, eastern and northwest New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. Including the recently completed projects listed below, Transwestern comprises approximately 2,700 miles of interstate pipeline with a capacity of 2.1 Bcf/d. The Transwestern pipeline has access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwest New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets like Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users. Transwestern transports natural gas in interstate commerce. As a result, Transwestern qualifies as a “natural gas company” under the NGA and is subject to the regulatory jurisdiction of the FERC. The operating results for Transwestern are included in ETP’s results on a consolidated basis as of the acquisition date (December 1, 2006). |
• | ETP’s interstate pipeline segment also includes its development of the Midcontinent Express Pipeline with KMP. The Midcontinent Express Pipeline is an approximately500-mile interstate natural gas pipeline that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transcontinental Gas Pipe Line Corporation’s, or Transco’s, interstate natural gas pipeline in Butler, Alabama. Transco’s pipeline provides producers in the Barnett Shale, Bossier Sands, the Fayetteville Shale in Arkansas and the Woodford/Caney Shale in Oklahoma access to the significant natural gas markets in the midwest, northeast, mid-Atlantic and southeast portion of the United States. The Midcontinent Express Pipeline consists of 266 miles of42-inch diameter pipeline, 201 miles of36-inch diameter pipeline and 40 miles of30-inch diameter pipeline and has multiple receipt and delivery interconnections. The first zone of the pipeline, from Bennington, |
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Oklahoma to Perryville, Louisiana, was placed in service in April 2009, and the second zone of the pipeline, from Perryville, Louisiana to Butler, Alabama, was placed in service on August 1, 2009. The first zone of the pipeline has an initial design capacity of 1.5 Bcf/d (taking into account the planned addition of compression by June 2010) and the second zone of the pipeline has an initial design capacity of 1.2 Bcf/d. MEP, the entity developing this pipeline, has received firm transportation commitments from customers for the full throughput design capacity for periods ranging from five to ten years. MEP has also received long-term firm transportation commitments from customers for a 0.3 Bcf/d planned expansion of the pipeline capacity, through additional compression, expected to be completed by July 2010. |
• | In October 2008, ETP entered into a 50/50 joint venture with KMP for the development of the Fayetteville Express Pipeline, an approximately187-mile42-inch diameter 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. In December 2009, FEP, the entity formed to own and operate this pipeline, received approval of its application for FERC authority to construct and operate this pipeline. The pipeline is expected to have an initial capacity of 2.0 Bcf/d. On December 17, 2009, the FERC issued an order granting Fayetteville Express Pipeline authorization to construct and operate the pipeline, subject to certain conditions, and FEP accepted the FERC’s certificate authorization on December 18, 2009. Subject to possible rehearing and judicial review, the pipeline is expected to be in service by late 2010. FEP has secured binding10-year commitments for transportation of quantities with energy equivalents totaling 1.8 Bcf/d. The new pipeline will interconnect with Natural Gas Pipeline Company of America, or NGPL, in White County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi, and ANR Pipeline Company in Quitman County, Mississippi. NGPL is operated and partially owned by Kinder Morgan, Inc., which owns the general partner of KMP. | |
• | In January 2009, ETP announced that it had entered into an agreement with a wholly owned subsidiary of Chesapeake Energy Corporation, or Chesapeake, to construct a178-mile42-inch diameter interstate natural gas pipeline, which we refer to as the Tiger Pipeline. The pipeline will connect to ETP’s dual42-inch diameter pipeline system near Carthage, Texas, extend through the heart of the Haynesville Shale and end near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana. The Tiger Pipeline is anticipated to have an initial throughput capacity of2.0 Bcf/d, which capacity may be increased up to 2.4 Bcf/d with added compression. The agreement with Chesapeake provides for a15-year commitment for firm transportation capacity of approximately 1.0 Bcf/d. ETP has also entered into agreements with EnCana Marketing (USA), Inc., a subsidiary of EnCana Corporation, and other shippers that provide for10-year commitments for firm transportation capacity on the Tiger Pipeline equal to the full initial design capacity of 2.0 Bcf/d in the aggregate. In August 2009, ETP filed an application for FERC authority to construct and operate this pipeline. Pending necessary regulatory approvals, including authorization from the FERC to construct the pipeline, the Tiger Pipeline is expected to be in service in the first half of 2011. |
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• | The Southeast Texas System is a 5,200-mile integrated system located in southeast Texas that gathers, compresses, treats, processes and transports natural gas from the Austin Chalk trend. The Southeast Texas System is a large natural gas gathering system covering 13 counties between Austin and Houston. The system includes the La Grange processing plant, 11 treating facilities and four conditioning facilities. This system is connected to the Katy Hub through the320-mile East Texas pipeline and is also connected to the Oasis pipeline, as well as two power plants. |
• | The North Texas System is a160-mile integrated system located in four counties in North Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett Shale trend. The system includes ETP’s Godley plant, as discussed above. |
• | The Canyon Gathering System consists of approximately 1,390 miles of gathering pipeline ranging in diameters from two inches to 16 inches in the Piceance-Uinta Basin of Colorado and Utah and six conditioning plants with an aggregated processing capacity of90 MMcf/d. | |
• | The midstream segment also includes ETP’s interests in various midstream assets located in Texas, New Mexico and Louisiana, with a combined capacity of approximately470 MMcf/d, as well as one processing facility. | |
• | Marketing operations, in which ETP markets the natural gas that flows through its assets, referred to as on-system gas, and attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells the natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. |
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• | the certification and construction of new facilities; | |
• | the review and approval of cost-based transportation rates; | |
• | the types of services that ETP’s regulated assets are permitted to perform; | |
• | the terms and conditions associated with these services; | |
• | the extension or abandonment of services and facilities; | |
• | the maintenance of accounts and records; | |
• | the acquisition and disposition of facilities; and | |
• | the initiation and discontinuation of services. |
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• | restricting how ETP can release materials or waste products into the air, water, or soils; | |
• | limiting or prohibiting construction activities in sensitive areas such as wetlands or areas of endangered species habitat, or otherwise constraining how or when construction is conducted; | |
• | requiring remedial action to mitigate pollution from former operations, or requiring plans and activities to prevent pollution from ongoing operations; and | |
• | imposing substantial liabilities on ETP for pollution resulting from its operations, including, for example, potentially enjoining the operations of facilities if it were determined that they were not in compliance with permit terms. |
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Name | Age | Position with Our General Partner | ||||
John W. McReynolds | 58 | Director, President and Chief Financial Officer | ||||
Sonia W. Aubé | 45 | Vice-President of Administration and Secretary | ||||
Kelcy L. Warren | 54 | Director and Chairman of the Board | ||||
Ray C. Davis | 67 | Director | ||||
Marshall S. McCrea, III | 50 | Director | ||||
David R. Albin | 50 | Director | ||||
K. Rick Turner | 51 | Director | ||||
Bill W. Byrne | 80 | Director | ||||
Paul E. Glaske | 76 | Director | ||||
John D. Harkey, Jr. | 49 | Director | ||||
Dan L. Duncan | 76 | Director | ||||
Dr. Ralph S. Cunningham | 69 | Director |
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• | an approximate 1.8% general partner interest, which ETE holds indirectly through its ownership interests in ETP GP; | |
• | 100% of the outstanding incentive distribution rights in ETP, which ETE holds indirectly through its ownership interests in ETP GP; and | |
• | approximately 62.5 million ETP common units, all of which are held directly by ETE. |
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Product | Volumes | Dollars | ||||||||
Nine Months Ended September 30, 2009 | ||||||||||
Propane Operations: | ||||||||||
Sales to Enterprise Entities | Propane (gallons) | 20,370 | $ | 14,046 | ||||||
Derivative Activity | — | 277 | ||||||||
Purchases from Enterprise Entities | Propane (gallons) | 206,344 | $ | 181,853 | ||||||
Derivative Activity | — | 38,392 | ||||||||
Natural Gas Operations: | ||||||||||
Sales to Enterprise Entities | NGLs (gallons) | 368,652 | $ | 259,417 | ||||||
Natural Gas (MMBtu) | 7,476 | 27,165 | ||||||||
Fees | — | (3,236 | ) | |||||||
Purchases from Enterprise Entities | Natural Gas Imbalances (MMBtu) | 617 | $ | 1,903 | ||||||
Natural Gas (MMBtu) | 7,089 | 27,359 | ||||||||
Fees | — | 42 |
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Issue | Amount | |||
(In millions) | ||||
5.65% Senior Notes due 2012 | $ | 400.0 | ||
6.00% Senior Notes due 2013 | $ | 350.0 | ||
8.50% Senior Notes due 2014 | $ | 350.0 | ||
5.95% Senior Notes due 2015 | $ | 750.0 | ||
6.125% Senior Notes due 2017 | $ | 400.0 | ||
6.70% Senior Notes due 2018 | $ | 600.0 | ||
9.70% Senior Notes due 2019 | $ | 600.0 | ||
9.00% Senior Notes due 2019 | $ | 650.0 | ||
6.625% Senior Notes due 2036 | $ | 400.0 | ||
7.50% Senior Notes due 2038 | $ | 550.0 | ||
Total | $ | 5,050.0 | ||
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• | incur indebtedness; | |
• | grant liens; | |
• | enter into mergers; | |
• | dispose of assets; | |
• | make distributions; | |
• | make certain investments; | |
• | enter into restrictive agreements; | |
• | enter into speculative hedging contracts; | |
• | commingle deposit accounts with certain subsidiaries; | |
• | amend our organizational documents or material agreements; | |
• | change our fiscal year; and | |
• | change the tax status of certain subsidiaries. |
• | On a quarterly basis and on the dates that we acquire or dispose of units or make permitted distributions, our leverage ratio, as described in the revolving credit facility, must not exceed 4.5 to 1.0, with a permitted increase to 5.0 to 1.0 during a specified acquisition period. | |
• | On a quarterly basis and on the dates that we acquire or dispose of units or make permitted distributions, our leverage ratio, as described in the revolving credit facility and calculated using ETP’s earnings before interest, taxes, depreciation and amortization, must not exceed 5.5 to 1.0. | |
• | The interest coverage ratio, as described in the revolving credit facility, must never be less than 3.0 to 1.0. | |
• | The value to loan ratio, as described in the revolving credit facility, must never be less than 2.0 to 1.0. |
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• | incur indebtedness; | |
• | grant liens; | |
• | enter into mergers; | |
• | dispose of assets; | |
• | make distributions during certain defaults and during any event of default; | |
• | make certain investments; | |
• | 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. |
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Fixed Interest | ||||||
Principal Amount | Rate per Annum | Maturity Date | ||||
(In millions) | ||||||
$88.0 | 5.39% | November 17, 2014 | ||||
$125.0 | 5.54% | November 17, 2016 | ||||
$82.0 | 5.64% | May 24, 2017 | ||||
$150.0 | 5.89% | May 24, 2022 | ||||
$75.0 | 6.16% | May 24, 2037 |
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• | be general unsecured senior obligations of ETE, ranking equally with all other existing and future unsecured and unsubordinated indebtedness of ETE; | |
• | initially be issued in an aggregate principal amount of $ with respect to the 2017 notes and an aggregate principal amount of $ with respect to the 2020 notes; | |
• | mature on February 28, 2017, with respect to the 2017 notes and February 28, 2020, with respect to the 2020 notes; | |
• | be issued in denominations of $2,000 and integral multiples of $1,000 in excess thereof; | |
• | bear interest at an annual rate of % with respect to the 2017 notes and an annual rate of % with respect to the 2020 notes; and | |
• | be redeemable at any time at our option at the redemption price described below under “— Optional Redemption.” |
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• | automatically upon any direct or indirect sale, transfer or other disposition, whether by way of merger or otherwise, to any Person that is not an Affiliate of ETE, of (a) all Capital Stock representing ownership of such Subsidiary Guarantor or (b) all or substantially all the assets of such Subsidiary Guarantor; | |
• | following delivery by ETE to the Trustee of an officer’s certificate to the effect that such Subsidiary Guarantor has been released from all guarantees or obligations in respect of any Indebtedness of ETE under the Credit Agreement; or | |
• | upon legal defeasance or satisfaction and discharge of the indenture as provided below under the caption “— Defeasance and Discharge.” |
• | will rank senior in right of payment to all future obligations of ETE that are, by their terms, expressly subordinated in right of payment to the notes andpari passuin right of payment with all existing and future senior obligations of ETE that are not so subordinated; | |
• | will be structurally subordinated to all liabilities and preferred equity of Subsidiaries of ETE that are not Subsidiary Guarantors; and | |
• | will be guaranteed by each Subsidiary of ETE that in the future is required to become a Subsidiary Guarantor. |
• | 100% of the principal amount of the notes to be redeemed; and | |
• | the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to the redemption date) discounted to the redemption date on a semi- |
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annual basis (assuming a360-day year consisting of twelve30-day months) at the applicable Treasury Yield plus 50 basis points; |
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• | it delivers all outstanding notes of such series to the Trustee for cancellation; or | |
• | all such notes not so delivered for cancellation have either become due and payable or will become due and payable at their stated maturity within one year or are called for redemption or are to be called for redemption under arrangements satisfactory to the Trustee within one year, and in the case of this bullet point, it has deposited with the Trustee in trust an amount of cash sufficient to pay the entire indebtedness of such notes, including interest to the stated maturity or applicable redemption date. |
• | a limited-purpose trust company organized under the New York Banking Law; | |
• | a “banking organization” under the New York Banking Law; | |
• | a member of the Federal Reserve System; | |
• | a “clearing corporation” under the New York Uniform Commercial Code; and | |
• | a “clearing agency” registered under the provisions of Section 17A of the Securities Exchange Act of 1934. |
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• | dealers in securities or currencies; | |
• | traders in securities that have elected themark-to-market method of accounting for their securities; | |
• | U.S. holders (as defined below) whose functional currency is not the U.S. dollar; | |
• | persons holding notes as part of a hedge, straddle, conversion or other “synthetic security” or integrated transaction; | |
• | U.S. expatriates; | |
• | financial institutions; | |
• | insurance companies; | |
• | regulated investment companies; | |
• | real estate investment trusts; | |
• | persons subject to the alternative minimum tax; | |
• | entities that are tax-exempt for U.S. federal income tax purposes; and | |
• | partnerships and other pass-through entities and holders of interests therein. |
• | an individual who is a U.S. citizen or U.S. resident alien; |
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• | a corporation, or other entity taxable as a corporation for U.S. federal income tax purposes, that was created or organized in or under the laws of the United States, any state thereof or the District of Columbia; | |
• | an estate whose income is subject to U.S. federal income taxation regardless of its source; or | |
• | a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust, or that has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person. |
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• | you do not own, actually or constructively, 10% or more of our capital or profits interests; | |
• | you are not a “controlled foreign corporation” that is related to us (actually or constructively); | |
• | you are not a bank whose receipt of interest on the notes is in connection with an extension of credit made pursuant to a loan agreement entered into in the ordinary course of your trade or business; and | |
• | interest on the notes is not effectively connected with your conduct of a U.S. trade or business. |
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• | the gain is effectively connected with the conduct by you of a U.S. trade or business (and, if required by an applicable income tax treaty, is treated as attributable to a permanent establishment maintained by you in the United States); or | |
• | you are an individual who has been present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met. |
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• | a United States person; | |
• | a foreign person that derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States; | |
• | a controlled foreign corporation for U.S. federal income tax purposes; or | |
• | a foreign partnership that, at any time during its taxable year, has more than 50% of its income or capital interests owned by United States persons or is engaged in the conduct of a U.S. trade or business. |
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Principal | Principal | |||||||
Amount of | Amount of | |||||||
Underwriters | 2017 Notes | 2020 Notes | ||||||
Credit Suisse Securities (USA) LLC | ||||||||
Morgan Stanley & Co. Incorporated | ||||||||
Wells Fargo Securities, LLC | ||||||||
Banc of America Securities LLC | ||||||||
UBS Securities LLC | ||||||||
BNP Paribas Securities Corp. | ||||||||
Deutsche Bank Securities Inc. | ||||||||
SunTrust Robinson Humphrey, Inc. | ||||||||
Total | $ | $ | ||||||
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• | to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities; | |
• | to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; or | |
• | in any other circumstances which do not require the publication by us of a prospectus pursuant to Article 3 of the Prospectus Directive. |
• | (A) it is a person whose ordinary activities involve it in acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of its business and (B) it has not offered or sold and will not offer or sell the notes other than to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of investments (as principal or as agent) for the purposes of their businesses or who it is reasonable to expect will acquire, hold, manage or dispose of investments (as principal or agent) for the purposes of their businesses where the issue of the notes would otherwise constitute a contravention of Section 19 of the Financial Services and Markets Act 2000 (the “FSMA”) by the Partnership; | |
• | it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the FSMA) received by it in connection with the issue or sale of the notes in circumstances in which Section 21(1) of the FSMA does not apply to us; and | |
• | it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the notes in, from or otherwise involving the United Kingdom. |
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• | the ability of our subsidiary, ETP, to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP; | |
• | the actual amount of cash distributions by ETP to us, which is affected by the amount, if any, of cash reserves established by the Board of Directors of the general partner of ETP and is outside of our control; | |
• | the amount of natural gas transported on ETP’s pipelines and gathering systems; | |
• | the level of throughput in ETP’s natural gas processing and treating facilities; | |
• | the fees ETP charges and the margins it realizes for its gathering, treating, processing, storage and transportation services; | |
• | the prices and market demand for, and the relationship between, natural gas and natural gas liquids, or NGLs; | |
• | energy prices generally; | |
• | the prices of natural gas and propane compared to the price of alternative and competing fuels; | |
• | the general level of petroleum product demand and the availability and price of propane supplies; | |
• | the level of domestic oil, propane and natural gas production; | |
• | the availability of imported oil and natural gas; | |
• | the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas; | |
• | actions taken by foreign oil and gas producing nations; | |
• | the political and economic stability of petroleum producing nations; | |
• | the effect of weather conditions on demand for oil, natural gas and propane; | |
• | availability of local, intrastate and interstate transportation systems; | |
• | the continued ability to find and contract for new sources of natural gas supply; | |
• | availability and marketing of competitive fuels; | |
• | the impact of energy conservation efforts; | |
• | energy efficiencies and technological trends; |
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• | governmental regulation and taxation; | |
• | changes to, and the application of, regulation of tariff rates and operational requirements related to ETP’s interstate and intrastate pipelines; | |
• | hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance; | |
• | the maturity of the propane industry and competition from other propane distributors; | |
• | competition from other midstream companies, interstate pipeline companies and propane distribution companies; | |
• | loss of key personnel; | |
• | loss of key natural gas producers or the providers of fractionation services; | |
• | reductions in the capacity or allocations of third-party pipelines that connect with ETP’s pipelines and facilities; | |
• | the effectiveness of risk-management policies and procedures and the ability of ETP’s liquids marketing counterparties to satisfy their financial commitments; | |
• | the nonpayment or nonperformance by ETP’s customers; | |
• | regulatory, environmental, political and legal uncertainties that may affect the timing and cost of ETP’s internal growth projects, such as ETP’s construction of additional pipeline systems; | |
• | risks associated with the construction of new pipelines and treating and processing facilities or additions to ETP’s existing pipelines and facilities, including difficulties in obtaining permits andrights-of-way or other regulatory approvals and the performance by third-party contractors; | |
• | the availability and cost of capital and ETP’s ability to access certain capital sources; | |
• | the further deterioration of the credit and capital markets; | |
• | the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to ETP’s financial results and to successfully integrate acquired businesses; | |
• | changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and | |
• | the costs and effects of legal and administrative proceedings. |
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Nine Months | Year | Four Months | ||||||||||||||||||||||||||
Ended | Ended | Ended | ||||||||||||||||||||||||||
September 30, | December 31, | December 31, | Year Ended August 31, | |||||||||||||||||||||||||
2009 | 2008 | 2007(1) | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||||||||
Ratio of earnings to fixed charges | 2.21 | 2.74 | 2.58 | 2.75 | 3.55 | 2.98 | 12.44 | |||||||||||||||||||||
(1) | In November 2007, we changed our fiscal year end from a year ending August 31 to a year ending December 31. Accordingly, the four months ended December 31, 2007 is treated as a transition period. |
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• | the form and title of the debt securities of that series; | |
• | the total principal amount of the debt securities of that series; | |
• | whether the debt securities will be issued in individual certificates to each holder or in the form of temporary or permanent global securities held by a depositary on behalf of holders; | |
• | the date or dates on which the principal of and any premium on the debt securities of that series will be payable; | |
• | any interest rate which the debt securities of that series will bear, the date from which interest will accrue, interest payment dates and record dates for interest payments; | |
• | any right to extend or defer the interest payment periods and the duration of the extension; | |
• | whether and under what circumstances any additional amounts with respect to the debt securities will be payable; | |
• | whether debt securities are entitled to the benefits of any guarantee of any Subsidiary Guarantor; | |
• | the place or places where payments on the debt securities of that series will be payable; | |
• | any provisions for optional redemption or early repayment; | |
• | any provisions that would require the redemption, purchase or repayment of debt securities; | |
• | the denominations in which the debt securities will be issued; |
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• | whether payments on the debt securities will be payable in foreign currency or currency units or another form and whether payments will be payable by reference to any index or formula; | |
• | the portion of the principal amount of debt securities that will be payable if the maturity is accelerated, if other than the entire principal amount; | |
• | any additional means of defeasance of the debt securities, any additional conditions or limitations to defeasance of the debt securities or any changes to those conditions or limitations; | |
• | any changes or additions to the events of default or covenants described in this prospectus; | |
• | any restrictions or other provisions relating to the transfer or exchange of debt securities; | |
• | any terms for the conversion or exchange of the debt securities for our other securities or securities of any other entity; and | |
• | any other terms of the debt securities of that series. |
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• | any debt security during a period beginning 15 business days prior to the mailing of the relevant notice of redemption and ending on the close of business on the day of mailing of such notice; or | |
• | any debt security that has been called for redemption in whole or in part, except the unredeemed portion of any debt security being redeemed in part. |
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• | our Annual Report onForm 10-K for the year ended December 31, 2008; | |
• | our Quarterly Reports onForm 10-Q for the quarters ended March 31, 2009, June 30, 2009 and September 30, 2009; and | |
• | our Current Reports onForm 8-K filed January 26, 2009, March 18, 2009, July 29, 2009, October 28, 2009, December 23, 2009 and January 20, 2010. |
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