Unaudited Condensed Consolidate
Unaudited Condensed Consolidated Balance Sheets (USD $) | ||
In Millions | 3 Months Ended
Mar. 31, 2010 | Dec. 31, 2009
|
Current assets: | ||
Cash and cash equivalents | 134.9 | 54.7 |
Restricted cash | 101.7 | 63.6 |
Accounts and notes receivable - trade, net of allowance for doubtful accounts | 3,056 | 3,099 |
Accounts receivable - related parties | 26.9 | 38.4 |
Inventories | 990.9 | 711.9 |
Prepaid and other current assets | 296.8 | 279.3 |
Total current assets | 4607.2 | 4246.9 |
Property, plant and equipment, net | 17735.3 | 17689.2 |
Investments in unconsolidated affiliates | 883.5 | 890.6 |
Intangible assets, net of accumulated amortization | 1035.2 | 1064.8 |
Goodwill | 2018.3 | 2018.3 |
Other assets | 221.6 | 241.8 |
Total assets | 26501.1 | 26151.6 |
Current liabilities: | ||
Current maturities of long-term debt | 175 | 0 |
Accounts payable - trade | 419 | 410.6 |
Accounts payable - related parties | 47.8 | 69.8 |
Accrued product payables | 3695.1 | 3,393 |
Accrued expenses | 79.4 | 108.5 |
Accrued interest | 170 | 228 |
Other current liabilities | 354.4 | 326.1 |
Total current liabilities | 4940.7 | 4,536 |
Long-term debt: | ||
Long-term debt (see Note 9) | 10915.7 | 11346.4 |
Deferred tax liabilities | 72.5 | 71.7 |
Other long-term liabilities | 160.2 | 155.2 |
Commitments and contingencies | ||
Limited Partners: | ||
Common units | 9575.4 | 9173.5 |
Restricted common units | 43.7 | 37.7 |
Class B Units | 118.5 | 118.5 |
General partner | 199.1 | 190.8 |
Accumulated other comprehensive loss | -54.6 | -8.4 |
Total Enterprise Products Partners L.P. partners' equity | 9882.1 | 9512.1 |
Noncontrolling interest | 529.9 | 530.2 |
Total equity | 10,412 | 10042.3 |
Total liabilities and equity | 26501.1 | 26151.6 |
Parenthetical Data To The Unaud
Parenthetical Data To The Unaudited Condensed Consolidated Balance Sheets (USD $) | ||
In Millions, except Share data | Mar. 31, 2010
| Dec. 31, 2009
|
Current assets: | ||
Allowance for doubtful accounts | 17.5 | 16.8 |
Accumulated amortization | 824.6 | $795 |
Limited Partners: | ||
Common units outstanding | 617,009,491 | 603,202,828 |
Restricted common units outstanding | 3,925,881 | 2,720,882 |
Class B Units Outstanding | 4,520,431 | 4,520,431 |
Unaudited Condensed Statements
Unaudited Condensed Statements of Consolidated Operations (USD $) | ||
In Millions, except Per Share data | 3 Months Ended
Mar. 31, 2010 | 3 Months Ended
Mar. 31, 2009 |
Revenues: | ||
Third parties | 8312.1 | 4667.4 |
Related parties | 232.4 | 219.5 |
Total revenues (see Note 11) | 8544.5 | 4886.9 |
Operating costs and expenses: | ||
Third parties | 7647.9 | 4147.1 |
Related parties | 324 | 229.5 |
Total operating costs and expenses | 7971.9 | 4376.6 |
General and administrative costs: | ||
Third parties | 14.1 | 7.9 |
Related parties | 23.5 | 27 |
Total general and administrative costs | 37.6 | 34.9 |
Total costs and expenses | 8009.5 | 4411.5 |
Equity in income of unconsolidated affiliates | 16 | 7.4 |
Operating income | 551 | 482.8 |
Other income (expense): | ||
Interest expense | -148.6 | -152.5 |
Interest income | 0.2 | 0.9 |
Other, net | -0.1 | 0.3 |
Total other expense, net | -148.5 | -151.3 |
Income before provision for income taxes | 402.5 | 331.5 |
Provision for income taxes | -8.7 | (16) |
Net income | 393.8 | 315.5 |
Net income attributable to noncontrolling interest | (16) | -90.2 |
Net income attributable to Enterprise Products Partners L.P. | 377.8 | 225.3 |
Net income allocated to: | ||
Limited partners | 317.4 | 186.3 |
General partner | 60.4 | $39 |
Earnings per unit: | ||
Basic earnings per unit (see Note 13) | 0.51 | 0.41 |
Diluted earnings per unit (see Note 13) | 0.5 | 0.41 |
1_Unaudited Condensed Statement
Unaudited Condensed Statements of Consolidated Comprehensive Income (USD $) | ||
In Millions | 3 Months Ended
Mar. 31, 2010 | 3 Months Ended
Mar. 31, 2009 |
Statement of Income and Comprehensive Income [Abstract] | ||
Net income | 393.8 | 315.5 |
Cash flow hedges: | ||
Commodity derivative instrument losses during period | -58.9 | (62) |
Reclassification adjustment for losses included in net income related to commodity derivative instruments | 16.5 | 32.2 |
Interest rate derivative instrument losses during period | -5.7 | -0.7 |
Reclassification adjustment for losses included in net income related to interest rate derivative instruments | 3.3 | 2.3 |
Foreign currency derivative losses during period | -0.1 | -10.6 |
Reclassification adjustment for gains included in net income related to foreign currency derivative instruments | -0.3 | 0 |
Total cash flow hedges | -45.2 | -38.8 |
Foreign currency translation adjustment | 0.6 | -0.4 |
Change in funded status of pension and postretirement plans, net of tax | -0.9 | 0 |
Total other comprehensive loss | -45.5 | -39.2 |
Comprehensive income | 348.3 | 276.3 |
Comprehensive income attributable to noncontrolling interest | -16.7 | -92.2 |
Comprehensive income attributable to Enterprise Products Partners L.P. | 331.6 | 184.1 |
2_Unaudited Condensed Statement
Unaudited Condensed Statements of Consolidated Cash Flows (USD $) | ||
In Millions | 3 Months Ended
Mar. 31, 2010 | 3 Months Ended
Mar. 31, 2009 |
Operating activities: | ||
Net income | 393.8 | 315.5 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||
Depreciation, amortization and accretion | 217.6 | 199.1 |
Non-cash impairment charges | 1.5 | 0 |
Equity in income of unconsolidated affiliates | (16) | -7.4 |
Distributions received from unconsolidated affiliates | 30.2 | 22.4 |
Operating lease expenses paid by EPCO | 0.2 | 0.2 |
Gain from asset sales and related transactions | -7.5 | -0.2 |
Deferred income tax expense | 1 | 0.9 |
Changes in fair market value of derivative instruments | -7.8 | -12.6 |
Effect of pension settlement recognition | -0.2 | -0.1 |
Net effect of changes in operating accounts (see Note 16) | 74.1 | -145.8 |
Net cash flows provided by operating activities | 686.9 | 372 |
Investing activities: | ||
Capital expenditures | -347.8 | -513.9 |
Contributions in aid of construction costs | 3.6 | 6.4 |
Increase in restricted cash | -38.1 | -40.7 |
Cash used for business combinations | -2.2 | 0 |
Acquisition of intangible assets | 0 | -1.4 |
Investments in unconsolidated affiliates | -7.7 | -7.1 |
Proceeds from asset sales and related transactions | 21.7 | 0.3 |
Other investing activities | 0 | 3.8 |
Cash used in investing activities | -370.5 | -552.6 |
Financing activities: | ||
Borrowings under debt agreements | 345.5 | 1163.4 |
Repayments of debt | (595) | -915.9 |
Debt issuance costs | -0.1 | -0.9 |
Cash distributions paid to partners | -407.3 | -279.7 |
Cash distributions paid to noncontrolling interest | -17.4 | -105.5 |
Cash contributions from noncontrolling interest | 0.2 | -0.6 |
Net cash proceeds from issuance of common units | 437.7 | 310.8 |
Acquisition of treasury units | -0.2 | 0 |
Cash provided by (used in) financing activities | -236.6 | 171.6 |
Effect of exchange rate changes on cash | 0.4 | (2) |
Net change in cash and cash equivalents | 79.8 | (9) |
Cash and cash equivalents, January 1 | 54.7 | 61.7 |
Cash and Cash Equivalents, March 31 | 134.9 | 50.7 |
3_Unaudited Condensed Statement
Unaudited Condensed Statements of Consolidated Equity (USD $) | |||||
In Millions | Limited Partner [Member]
| General Partner [Member]
| Accumulated Other Comprehensive Income [Member]
| Noncontrolling Interest [Member]
| Total
|
Partners' Capital, Beginning Balance at Dec. 31, 2008 | 6063.1 | 123.6 | -97.2 | 3206.4 | 9295.9 |
Net income | 186.3 | 39 | 0 | 90.2 | 315.5 |
Operating lease expenses paid by EPCO | 0.2 | 0 | 0 | 0 | 0.2 |
Cash distributions paid to partners | -239.5 | -40.1 | 0 | 0 | -279.6 |
Unit option reimbursements to EPCO | -0.1 | 0 | 0 | 0 | -0.1 |
Cash distributions paid to noncontrolling interest | 0 | 0 | 0 | 105.5 | -105.5 |
Net cash proceeds from issuance of common units | 304.5 | 6.2 | 0 | 0 | 310.7 |
Cash proceeds from exercise of unit options | 0.1 | 0 | 0 | 0 | 0.1 |
Cash contributions from noncontrolling interest | 0 | 0 | 0 | -0.6 | -0.6 |
Amortization of equity awards | 2.7 | 0.1 | 0 | 1.1 | 3.9 |
Foreign currency translation adjustment | 0 | 0 | -0.4 | 0 | -0.4 |
Cash flow hedges | 0 | 0 | -40.8 | 2 | -38.8 |
Partners' Capital, Ending Balance at Mar. 31, 2009 | 6317.3 | 128.8 | -138.4 | 3193.6 | 9501.3 |
Partners' Capital, Beginning Balance at Dec. 31, 2009 | 9329.7 | 190.8 | -8.4 | 530.2 | 10042.3 |
Net income | 317.4 | 60.4 | 0 | 16 | 393.8 |
Operating lease expenses paid by EPCO | 0.2 | 0 | 0 | 0 | 0.2 |
Cash distributions paid to partners | -345.5 | -60.9 | 0 | 0 | -406.4 |
Unit option reimbursements to EPCO | -0.9 | 0 | 0 | 0 | -0.9 |
Cash distributions paid to noncontrolling interest | 0 | 0 | 0 | 17.4 | -17.4 |
Net cash proceeds from issuance of common units | 428.3 | 8.8 | 0 | 0 | 437.1 |
Cash proceeds from exercise of unit options | 0.6 | 0 | 0 | 0 | 0.6 |
Cash contributions from noncontrolling interest | 0 | 0 | 0 | 0.2 | 0.2 |
Amortization of equity awards | 8 | 0 | 0 | 0.2 | 8.2 |
Acquisition of treasury units | -0.2 | 0 | 0 | 0 | -0.2 |
Foreign currency translation adjustment | 0 | 0 | 0.6 | 0 | 0.6 |
Change in funded status of pension and postretirement plans | 0 | 0 | -0.9 | 0 | -0.9 |
Cash flow hedges | 0 | 0 | -45.9 | 0.7 | -45.2 |
Partners' Capital, Ending Balance at Mar. 31, 2010 | 9737.6 | 199.1 | -54.6 | 529.9 | $10,412 |
Partnership Organization and Ba
Partnership Organization and Basis of Presentation | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Partnership Organization and Basis of Presentation | Note 1.Partnership Organization and Basis of Presentation We are a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol EPD.We were formed in April 1998 to own and operate certain natural gas liquids (NGLs) related businesses of EPCO.We conduct substantially all of our business through our wholly owned subsidiary, EPO.We are owned 98% by our limited partners and 2% by our general partner, EPGP.Enterprise GP Holdings owns 100% of EPGP.The general partner of Enterprise GP Holdings is EPE Holdings, a wholly owned subsidiary of Dan Duncan LLC.Mr. Dan L. Duncan owned all of the membership interests of Dan Duncan LLC prior to his death on March 29, 2010.All of the membership interests of Dan Duncan LLC are currently owned of record collectively by the DD LLC Trustees.We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under the collective common control of the DD LLC Trustees and the EPCO Trustees.The EPCO Trustees are collectively the controlling record shareholders of EPCO. For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments.We control Duncan Energy Partners through our ownership of its general partner.Also, due to common control of the entities by Dan L. Duncan during his lifetime, and thereafter by the DD LLC Trustees and the EPCO Trustees, collectively, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners.Public ownership of Duncan Energy Partners net assets and earnings are presented as a component of noncontrolling interest in our consolidated financial statements.The borrowings of Duncan Energy Partners are presented as part of our consolidated debt.However, neither Enterprise Products Partners nor EPO have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners. TEPPCO Merger and Basis of Presentation Our consolidated financial statements and business segments were recast in connection with the TEPPCO Merger. On October 26, 2009, the related mergers of our wholly owned subsidiaries with TEPPCO and TEPPCO GP were completed.Under terms of the merger agreements, TEPPCO and TEPPCO GP became wholly owned subsidiaries of ours, and each of TEPPCOs unitholders, except for a privately held affiliate of EPCO, were entitled to receive 1.24 of our common units for each TEPPCO unit.In total, we issued an aggregate of 126,932,318 common units and 4,520,431 Class B units (described below) as consideration in the TEPPCO Merger for both TEPPCO units and the TEPPCO GP membership interests.TEPPCOs units, which had been trading on the NYSE under the ticker symbol TPP, have been delisted and are no longer publicly traded.On October 27, 2009, our TEPPCO and TEPPCO GP equity interests were contributed to EPO, and TEPPCO and TEPPCO GP became wholly owned subsidiaries of EPO. A privately held affiliate of EPCO exchanged a portion of its TEPPCO units, based on the 1.24 exch |
General Accounting Matters
General Accounting Matters | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
General Accounting Matters | Note 2.General Accounting Matters Estimates Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities.Our actual results could differ from these estimates.On an ongoing basis, management reviews its estimates based on currently available information.Changes in facts and circumstances may result in revised estimates. Fair Value Information Cash and cash equivalents and restricted cash, accounts receivable, accounts payable and accrued expenses, and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature.The estimated fair values of our fixed-rate debt are based on quoted market prices for such debt or debt of similar terms and maturities.The carrying amounts of our variable-rate debt obligations reasonably approximate their fair values due to their variable interest rates.See Note 4 for fair value information associated with our derivative instruments. The following table presents the estimated fair values of our financial instruments at the dates indicated: March 31, 2010 December 31, 2009 Carrying Fair Carrying Fair Financial Instruments Value Value Value Value Financial assets: Cash and cash equivalents and restricted cash $ 236.6 $ 236.6 $ 118.3 $ 118.3 Accounts receivable 3,082.9 3,082.9 3,137.4 3,137.4 Financial liabilities: Accounts payable and accrued expenses 4,411.3 4,411.3 4,209.9 4,209.9 Other current liabilities (excluding derivative instruments) 222.8 222.8 233.1 233.1 Fixed-rate debt (principal amount) 10,532.7 11,156.2 10,586.7 11,056.2 Variable-rate debt 514.8 514.8 710.3 710.3 Restricted Cash Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and related physical natural gas and NGL purchases.Additional cash may be restricted to maintain this portfolio as commodity prices fluctuate or deposit requirements change.At March 31, 2010 and December 31, 2009, our restricted cash amounts were $101.7 million and $63.6 million, respectively.See Note 4 for information regarding derivative instruments and hedging activities. |
Equity-based Awards
Equity-based Awards | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Equity-based Awards | Note 3.Equity-based Awards The following table summarizes the expense we recognized in connection with equity-based awards for the periods indicated: For the Three Months Ended March 31, 2010 2009 Restricted unit awards (1) $ 5.3 $ 2.4 Unit option awards (1) 0.9 0.1 Unit appreciation rights (2) 0.1 -- Profits interests awards (1) 1.8 1.4 Total compensation expense $ 8.1 $ 3.9 (1) Accounted for as equity-classified awards. (2) Accounted for as liability-classified awards. The fair value of an equity-classified award (e.g., a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period.Compensation expense for liability-classified awards (e.g., unit appreciation rights (UARs)) is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period.Liability-classified awards are settled in cash upon vesting. At March 31, 2010, the active long-term incentive plans were the Enterprise Products 1998 Long-Term Incentive Plan, the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan and the 2010 Duncan Energy Partners L.P. Long-Term Incentive Plan.In addition, we had unvested awards issued, but are not issuing further awards, under the Enterprise Products 2006 TPP Long-Term Incentive Plan (2006 Plan). An allocated portion of the fair value of these long-term incentive plan equity-based awards is charged to us under the administrative services agreement (ASA).See Note 12 for a general description of the ASA with EPCO.With the exception of certain amounts recorded in connection with EPCO Unit, we are not responsible for reimbursing EPCO for any expenses associated with such awards.We recognize an expense for our allocated share of the grant date fair value of such awards, with an offsetting amount recorded in equity.Beginning in February 2009, the ASA was amended to provide that we and other affiliates of EPCO will reimburse EPCO for our allocated share of distributions of cash or securities made to the Class B limited partners of EPCO Unit.Our reimbursements to EPCO in connection with EPCO Unit were $0.1 million during each of the three months ended March 31, 2010 and 2009. Restricted Unit Awards Restricted unit awards allow recipients to acquire our common units or common units of Duncan Energy Partners (at no cost to the recipient) once a defined vesting period expires, subject to customary forfeiture provisions.The majority of these awards are subject to cliff vesting, the restrictions on such awards generally lapse four years from the date of grant.There are also awards that are subject to graded vesting provisions by which one-fourth of each award vests on each of the first, second, third and fourth anniversaries of the date of grant.The fair value of restricted units is based on the market price per unit of the underlying security on the date of grant.Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures.Compensation expense for awards with graded vesting provisions is recogn |
Derivative Instruments, Hedging
Derivative Instruments, Hedging Activities and Fair Value Measurements | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Derivative Instruments, Hedging Activities and Fair Value Measurements | Note 4.Derivative Instruments, Hedging Activities and Fair Value Measurements In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates, commodity prices and, to a limited extent, foreign exchange rates.In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments.Derivatives are instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values.Fair value is generally defined as the amount at which a derivative instrument could be exchanged in a current transaction between willing parties, not in a forced sale.Typical derivative instruments include futures, forward contracts, swaps, options and other instruments with similar characteristics.Substantially all of our derivatives are used for non-trading activities. We are required to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet.While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of the derivative instruments are reported in different ways depending on the nature and effectiveness of the hedging activities to which they are related.After meeting specified conditions, a qualified derivative may be specifically designated as a total or partial hedge of: Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment - In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change. Variable cash flows of a forecasted transaction - In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income (loss) (OCI) and is reclassified into earnings when the forecasted transaction affects earnings. Foreign currency exposure - A foreign currency hedge can be treated as either a fair value hedge or a cash flow hedge depending on the risk being hedged. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of changes in the fair value of a hedged item at inception and throughout the life of the hedging relationship.The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period.Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item.Any ineffectiveness associated with a hedge relationship is recognized in earnings immediately.Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item. A contract designated as a cash flow hedge of an anticipated transaction that is probable of not occurring is immediately recognized in earnings. Interest Rate Derivative Instruments We utilize interest rate swaps, treasury locks and |
Inventories
Inventories | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Inventories | Note 5.Inventories Our inventory amounts were as follows at the dates indicated: March 31, December 31, 2010 2009 Working inventory (1) $ 702.8 $ 466.4 Forward sales inventory (2) 288.1 245.5 Total inventory $ 990.9 $ 711.9 (1) Working inventory is comprised of inventories of natural gas, NGLs, crude oil, refined products, lubrication oils and certain petrochemical products that are either available-for-sale or used in the provision for services. (2) Forward sales inventory consists of identified natural gas, NGL, refined product and crude oil volumes dedicated to the fulfillment of forward sales contracts. In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties), these volumes are valued at market-based prices during the month in which they are acquired. The following table summarizes our cost of sales and lower of cost or market (LCM) adjustment amounts for the periods indicated: For the Three Months Ended March 31, 2010 2009 Cost of sales (1) $ 7,342.3 $ 3,817.9 LCM adjustments 5.7 4.3 (1) Cost of sales is included in Operating costs and expenses, as presented on our Unaudited Condensed Statements of Consolidated Operations.The fluctuation in this amount quarter-to-quarter is primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities. |
Property, Plant and Equipment
Property, Plant and Equipment | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Property, Plant and Equipment | Note 6.Property, Plant and Equipment Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated: Estimated Useful Life March 31, December 31, in Years 2010 2009 Plants and pipelines (1) 3-45 (5) $ 18,077.8 $ 17,681.9 Underground and other storage facilities (2) 5-40 (6) 1,294.6 1,280.5 Platforms and facilities (3) 20-31 637.6 637.6 Transportation equipment (4) 3-10 61.2 60.1 Marine vessels 15-30 559.0 559.4 Land 82.9 82.9 Construction in progress 1,021.8 1,207.2 Total 21,734.9 21,509.6 Less accumulated depreciation 3,999.6 3,820.4 Property, plant and equipment, net $ 17,735.3 $ 17,689.2 (1) Plants and pipelines include processing plants; NGL, petrochemical, crude oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) Platforms and facilities include offshore platforms and related facilities and other associated assets. (4) Transportation equipment includes vehicles and similar assets used in our operations. (5) In general, the estimated useful lives of major components of this category are as follows:processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; delivery facilities, 20-40 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of major components of this category are as follows:underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years. The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated: For the Three Months Ended March 31, 2010 2009 Depreciation expense (1) $ 180.3 $ 158.6 Capitalized interest (2) 10.5 17.4 (1) Depreciation expense is a component of Costs and expenses as presented in our Unaudited Condensed Statements of Consolidated Operations. (2) Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded. Asset Retirement Obligations We have recorded asset retirement obligations (AROs) related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations.In general, our AROs primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities.In addition, our AROs may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos. The following table presents information regarding our AROs since December 31, |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Investments in Unconsolidated Affiliates | Note 7.Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for using the equity method of accounting.We group our investments in unconsolidated affiliates according to the business segment to which they relate (see Note 11 for a general discussion of our business segments).The following table shows our ownership interest and investments in unconsolidated affiliates by business segment at the dates indicated: Ownership Interest at March 31, March 31, December 31, 2010 2010 2009 NGL Pipelines Services: Venice Energy Service Company, L.L.C. 13.1% $ 31.6 $ 32.6 K/D/S Promix, L.L.C. (Promix) 50% 50.1 48.9 Baton Rouge Fractionators LLC 32.2% 22.5 22.2 Skelly-Belvieu Pipeline Company, L.L.C. 50% 34.5 37.9 Onshore Natural Gas Pipelines Services: Evangeline (1) 49.5% 5.8 5.6 White River Hub, LLC 50% 26.6 26.4 Onshore Crude Oil Pipelines Services: Seaway Crude Pipeline Company (Seaway) 50% 177.2 178.5 Offshore Pipelines Services: Poseidon Oil Pipeline Company, L.L.C. (Poseidon) 36% 61.0 61.7 Cameron Highway Oil Pipeline Company (Cameron Highway) 50% 237.5 239.6 Deepwater Gateway, L.L.C. 50% 100.7 101.8 Neptune Pipeline Company, L.L.C. 25.7% 55.6 53.8 Petrochemical Refined Products Services: Baton Rouge Propylene Concentrator, LLC 30% 11.1 11.1 Centennial Pipeline LLC (Centennial) 50% 65.6 66.7 Other (2) Various 3.7 3.8 Total $ 883.5 $ 890.6 (1) Evangeline refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2) Other unconsolidated affiliates include a 50% interest in a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest in a company that provides logistics communications solutions between petroleum pipelines and their customers. On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire.Such excess cost amounts are included within the carrying values of our investments in unconsolidated affiliates.The following table summarizes the unamortized excess cost amounts by business segment at the dates indicated: March 31, December 31, 2010 2009 NGL Pipelines Services $ 26.4 $ 27.1 Onshore Crude Oil Pipelines Services 20.2 20.4 Offshore Pipelines Services 17.0 17.3 Petrochemical Refined Products Services 3.3 4.0 Total $ 66.9 $ 68.8 Such excess cost amounts were attributable to the underlying tangible and amortizable intangible assets of certain unconsolidated affiliates.We amortize such excess cost amounts as a reduction in equity earnings in a manner similar to depreciation.The following table presents our amortization of such excess cost amounts by business segment for the periods indicated: For the Three Months Ended March 31, 2010 2009 NGL Pipelines Services $ 0.2 $ 0.2 Onshore Crude Oil Pi |
Intangible Assets and Goodwill
Intangible Assets and Goodwill | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Intangible Assets and Goodwill | Note 8.Intangible Assets and Goodwill Identifiable Intangible Assets The following table summarizes our intangible assets by segment at the dates indicated: March 31, 2010 December 31, 2009 Gross Accum. Carrying Gross Accum. Carrying Value Amort. Value Value Amort. Value NGL Pipelines Services: Customer relationship intangibles $ 237.4 $ (90.6 ) $ 146.8 $ 237.4 $ (86.5 ) $ 150.9 Contract-based intangibles 321.4 (161.9 ) 159.5 321.4 (156.7 ) 164.7 Segment total 558.8 (252.5 ) 306.3 558.8 (243.2 ) 315.6 Onshore Natural Gas Pipelines Services: Customer relationship intangibles 372.0 (129.3 ) 242.7 372.0 (124.3 ) 247.7 Contract-based intangibles 565.3 (295.0 ) 270.3 565.3 (285.8 ) 279.5 Segment total 937.3 (424.3 ) 513.0 937.3 (410.1 ) 527.2 Onshore Crude Oil Pipelines Services: Contract-based intangibles 10.0 (3.6 ) 6.4 10.0 (3.5 ) 6.5 Segment total 10.0 (3.6 ) 6.4 10.0 (3.5 ) 6.5 Offshore Pipelines Services: Customer relationship intangibles 205.8 (108.6 ) 97.2 205.8 (105.3 ) 100.5 Contract-based intangibles 1.2 (0.3 ) 0.9 1.2 (0.2 ) 1.0 Segment total 207.0 (108.9 ) 98.1 207.0 (105.5 ) 101.5 Petrochemical Refined Products Services: Customer relationship intangibles 104.6 (20.1 ) 84.5 104.6 (18.8 ) 85.8 Contract-based intangibles 42.1 (15.2 ) 26.9 42.1 (13.9 ) 28.2 Segment total 146.7 (35.3 ) 111.4 146.7 (32.7 ) 114.0 Total all segments $ 1,859.8 $ (824.6 ) $ 1,035.2 $ 1,859.8 $ (795.0 ) $ 1,064.8 The following table presents the amortization expense of our intangible assets by segment for the periods indicated: For the Three Months Ended March 31, 2010 2009 NGL Pipelines Services $ 9.3 $ 9.8 Onshore Natural Gas Pipelines Services 14.2 14.6 Onshore Crude Oil Pipelines Services 0.1 0.1 Offshore Pipelines Services 3.4 3.9 Petrochemical Refined Products Services 2.6 2.7 Total $ 29.6 $ 31.1 The following table presents forecasted amortization expense associated with existing intangible assets for the years presented: Remainder of 2010 2011 2012 2013 2014 $ 85.1 $ 105.7 $ 70.0 $ 81.9 $ 76.5 In general, our intangible assets fall within two categories customer relationship and contract-based intangible assets.The values assigned to such intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits of associated resource bases are estimated to be consumed or otherwise used, as appropriate. Customer relationship intangible assets.Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations and asset purchases whereby (i) we acquired information about or access to customers and now have regu |
Debt Obligations
Debt Obligations | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Debt Obligations | Note 9.Debt Obligations Our consolidated debt obligations consisted of the following at the dates indicated: March 31, December 31, 2010 2009 EPO senior debt obligations: Multi-Year Revolving Credit Facility, variable-rate, due November 2012 $ -- $ 195.5 Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 -- 54.0 Petal GO Zone Bonds, variable-rate, due August 2034 57.5 57.5 Senior Notes B, 7.50% fixed-rate, due February 2011 (1) 450.0 450.0 Senior Notes C, 6.375% fixed-rate, due February 2013 350.0 350.0 Senior Notes D, 6.875% fixed-rate, due March 2033 500.0 500.0 Senior Notes G, 5.60% fixed-rate, due October 2014 650.0 650.0 Senior Notes H, 6.65% fixed-rate, due October 2034 350.0 350.0 Senior Notes I, 5.00% fixed-rate, due March 2015 250.0 250.0 Senior Notes J, 5.75% fixed-rate, due March 2035 250.0 250.0 Senior Notes K, 4.95% fixed-rate, due June 2010 (1) 500.0 500.0 Senior Notes L, 6.30% fixed-rate, due September 2017 800.0 800.0 Senior Notes M, 5.65% fixed-rate, due April 2013 400.0 400.0 Senior Notes N, 6.50% fixed-rate, due January 2019 700.0 700.0 Senior Notes O, 9.75% fixed-rate, due January 2014 500.0 500.0 Senior Notes P, 4.60% fixed-rate, due August 2012 500.0 500.0 Senior Notes Q, 5.25% fixed-rate, due January 2020 500.0 500.0 Senior Notes R, 6.125% fixed-rate, due October 2039 600.0 600.0 Senior Notes S, 7.625% fixed-rate, due February 2012 490.5 490.5 Senior Notes T, 6.125% fixed-rate, due February 2013 182.5 182.5 Senior Notes U, 5.90% fixed-rate, due April 2013 237.6 237.6 Senior Notes V, 6.65% fixed-rate, due April 2018 349.7 349.7 Senior Notes W, 7.55% fixed-rate, due April 2038 399.6 399.6 TEPPCO senior debt obligations: TEPPCO Senior Notes 40.1 40.1 Duncan Energy Partners debt obligations: DEP Revolving Credit Facility, variable-rate, due February 2011 (2) 175.0 175.0 DEP Term Loan, variable-rate, due December 2011 282.3 282.3 Total principal amount of senior debt obligations 9,514.8 9,764.3 EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 550.0 550.0 EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068 682.7 682.7 EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 285.8 285.8 TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067 14.2 14.2 Total principal amount of senior and junior debt obligations 11,047.5 11,297.0 Other, non-principal amounts: Change in fair value of debt-related derivative instruments (see Note 4) 41.2 44.4 Unamortized discounts, net of premiums (18.4 ) (18.7 ) Unamortized deferred net gains related to terminated interest rate swaps (see Note 4) 20.4 23.7 Total other, non-principal amounts 43.2 49.4 Less current maturities of debt (2) (175.0 ) -- Total long-term debt $ 10,915.7 $ 11,346.4 (1) Long-term and current maturities of debt reflect the classification of such obligations at March 3 |
Equity and Distributions
Equity and Distributions | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Equity and Distributions | Note 10.Equity and Distributions Our common units represent limited partner interests, which give holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under ourFifth Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the Partnership Agreement).We are managed by our general partner, EPGP. In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and limited partners.The capital account provisions of the Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to GAAP-based equity amounts presented in our consolidated financial statements.Earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests. Registration Statements and Equity Offerings We have filed registration statements with the SEC authorizing the issuance of up to an aggregate of 70,000,000 common units in connection with our distribution reinvestment plan (DRIP).The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units.A total of 36,175,679 common units have been issued under the DRIP registration statement through March 31, 2010. We have filed a registration statement with the SEC authorizing the issuance of up to an aggregate of 1,200,000 common units in connection with our employee unit purchase plan (EUPP).Under this plan, employees of EPCO can purchase our common units at a 10% discount through payroll deductions.A total of 871,169 common units have been issued to employees under this plan through March 31, 2010. We have also filed a universal shelf registration statement with the SEC that allows us to issue an unlimited amount of debt and equity securities.We have issued 29,852,500 common units in underwritten offerings under this registration statement generating $795.3 million of net cash proceeds through March 31, 2010.In addition, we have issued $4.0 billion of senior notes under this registration statement through March 31, 2010. In January 2010, we issued 10,925,000 common units (including an over-allotment of 1,425,000 common units) to the public at an offering price of $32.42 per unit.We used the net cash proceeds of $343.3 million to temporarily reduce borrowings outstanding under EPOs Multi-Year Revolving Credit Facility and for general partnership purposes. In April 2010, we issued 13,800,000 common units (including an over-allotment of 1,800,000 common units) to the public at an offering price of $35.55 per unit.See Note 18 for additional information. The following table reflects the number of common units issued and the net cash proceeds received from underwritten and other common unit offerings completed during the three months ended March 31, 2010: Net Cash Proceeds from Issuance of Common Units Number of Contributed Con |
Business Segments
Business Segments | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Business Segments | Note 11.Business Segments We have five reportable business segments: NGL Pipelines Services, Onshore Natural Gas Pipelines Services, Onshore Crude Oil Pipelines Services, Offshore Pipelines Services and Petrochemical Refined Products Services.Our business segments are generally organized and managed according to the type of services rendered (or technologies employed) and products produced and/or sold. We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations.This measure forms the basis of our internal financial reporting and is used by our management in deciding how to allocate capital resources among business segments.We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.The GAAP financial measure most directly comparable to total segment gross operating margin is operating income.Our non-GAAP financial measure of total segment gross operating margin should not be considered an alternative to GAAP operating income. We define total segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) non-cash consolidated asset impairment charges; (iii) operating lease expenses for which we do not have the payment obligation; (iv) gains and losses from asset sales and related transactions; and (v) general and administrative costs.Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions.In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation.Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, the cumulative effect of changes in accounting principles and extraordinary charges.Gross operating margin is presented on a 100% basis before the allocation of earnings to noncontrolling interests. We consolidate the financial statements of Duncan Energy Partners with those of our own.As a result, our consolidated gross operating margin amounts include 100% of the gross operating margin amounts of Duncan Energy Partners. The following table shows our measurement of total segment gross operating margin for the periods indicated: For the Three Months Ended March 31, 2010 2009 Revenues $ 8,544.5 $ 4,886.9 Less: Operating costs and expenses (7,971.9 ) (4,376.6 ) Add: Equity in income of unconsolidated affiliates 16.0 7.4 Depreciation, amortization and accretion in operating costs and expenses (1) 212.4 196.4 Non-cash impairment charges 1.5 -- Operating lease expenses paid by EPCO 0.2 0.2 Gain from asset sales and related transactions in operating costs and expenses (2) (7.3 ) (0.2 ) Total segment gross operating margin $ 795.4 $ 714.1 (1) Amount is a component |
Related Party Transactions
Related Party Transactions | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Related Party Transactions | Note 12.Related Party Transactions The following table summarizes our related party transactions for the periods indicated: For the Three Months Ended March 31, 2010 2009 Revenues related parties: Energy Transfer Equity and subsidiaries $ 186.6 $ 162.8 Unconsolidated affiliates 45.8 56.7 Total revenue related parties $ 232.4 $ 219.5 Costs and expenses related parties: EPCO and affiliates $ 158.4 $ 143.8 Energy Transfer Equity and subsidiaries 176.9 91.4 Unconsolidated affiliates 12.2 6.9 Other -- 14.4 Total costs and expenses related parties $ 347.5 $ 256.5 The following table summarizes our related party receivable and payable amounts at the dates indicated: March 31, December 31, 2010 2009 Accounts receivable - related parties: EPCO and affiliates $ 0.3 $ -- Energy Transfer Equity and subsidiaries 11.3 28.2 Other 15.3 10.2 Total accounts receivable related parties $ 26.9 $ 38.4 Accounts payable - related parties: EPCO and affiliates $ 2.1 $ 26.8 Energy Transfer Equity and subsidiaries 37.5 33.4 Other 8.2 9.6 Total accounts payable related parties $ 47.8 $ 69.8 We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. Relationship with EPCO and Affiliates We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not a part of our consolidated group of companies: EPCO and its privately held affiliates; EPGP, our sole general partner; Enterprise GP Holdings, which owns and controls our general partner; and the Employee Partnerships (see Note 3). EPCO is a privately held company controlled collectively by the EPCO Trustees.At March 31, 2010, EPCO and its affiliates (including Dan Duncan LLC and two Duncan family trusts the beneficiaries of which include the estate of Dan L. Duncan) beneficially owned interests in the following entities: Percentage of Number of Units Outstanding Units Enterprise Products Partners (1) (2) 195,882,296 31.3% Enterprise GP Holdings (3) 108,919,199 78.2% (1) Includes 4,520,431 Class B units owned by a privately held affiliate of EPCO and 21,563,177 common units owned by Enterprise GP Holdings. (2) Enterprise GP Holdings owns 100% of our general partner, EPGP. (3) An affiliate of EPCO, Dan Duncan LLC, which is controlled by the DD LLC Trustees, who are currently the same individuals as the EPCO Trustees and the independent co-executors of the estate of Dan L. Duncan, also owns 100% of the general partner of Enterprise GP Holdings, EPE Holdings. The principal business activity of EPGP is to act as our sole managing partner.The executive officers and certain of the directors of EPGP are employees of EPCO.The following table presents cash distributions received by EPGP for the periods indicated: For the Three Months Ended March 31, 2010 2009 General partner di |
Earnings Per Unit
Earnings Per Unit | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Earnings Per Unit | Note 13.Earnings Per Unit Basic earnings per unit is computed by dividing net income or loss available to limited partner interests by the weighted-average number of distribution-bearing units outstanding during a period.Diluted earnings per unit is computed by dividing net income or loss available to limited partner interests by the sum of (i) the weighted-average number of distribution-bearing units outstanding during a period (as used in determining basic earnings per unit); (ii) the weighted-average number of Class B units outstanding during a period and (iii) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the incremental option units). In a period of net losses, Class B units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect.The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase common units at an average market value during the period.The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. The amount of net income or loss available to limited partner interests is net of our general partners share of such earnings.The following table presents the net income available to EPGP for the periods indicated: For the Three Months Ended March 31, 2010 2009 Net income attributable to Enterprise Products Partners L.P. $ 377.8 $ 225.3 Less incentive earnings allocations to EPGP (53.9 ) (35.2 ) Net income available after incentive earnings allocation 323.9 190.1 Multiplied by EPGP ownership interest 2.0 % 2.0 % Standard earnings allocation to EPGP $ 6.5 $ 3.8 Incentive earnings allocation to EPGP $ 53.9 $ 35.2 Standard earnings allocation to EPGP 6.5 3.8 Net income available to EPGP 60.4 39.0 Adjustment for master limited partnerships (1) 2.9 1.4 Net income available to EPGP for EPU purposes $ 63.3 $ 40.4 (1) FASB guidance specific to master limited partnerships has been applied for purposes of computing basic and diluted earnings per unit. The following table presents our calculation of basic and diluted earnings per unit for the periods indicated: For the Three Month Ended March 31, 2010 2009 BASIC EARNINGS PER UNIT Numerator Net income attributable to Enterprise Products Partners L.P. $ 377.8 $ 225.3 Net income available to EPGP for EPU purposes (63.3 ) (40.4 ) Net income available to limited partners $ 314.5 $ 184.9 Denominator Weighted average common units 614.6 450.7 Weighted average time-vested restricted units 3.2 2.0 Total 617.8 452.7 Basic earnings per unit Net income per unit before EPGP earnings allocation $ 0.61 $ 0.50 Net income available to EPGP (0.10 ) (0.09 ) Net income available to limited partners $ 0.51 $ 0.41 DILUTED EARNINGS PER UNIT Numerator |
Commitments and Contingencies
Commitments and Contingencies | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Commitments and Contingencies | Note 14.Commitments and Contingencies Litigation On occasion, we or our unconsolidated affiliates are named as defendants in litigation and legal proceedings relating to our normal business activities, including regulatory and environmental matters.Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings.We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. We evaluate our ongoing litigation based upon a combination of litigation and settlement alternatives.These reviews are updated as the facts and combinations of the cases develop or change.Assessing and predicting the outcome of these matters involves substantial uncertainties.In the event that the assumptions we used to evaluate these matters change in future periods or new information becomes available, we may be required to record a liability for an adverse outcome.In an effort to mitigate potential adverse consequences of litigation, we could also seek to settle legal proceedings brought against us.We have not recorded any significant reserves for any litigation in our financial statements. The Attorney General of Colorado on behalf of the Colorado Department of Public Health and Environment (CDPHE) filed suit against us and others on April 15, 2008 in connection with the construction of a pipeline near Parachute, Colorado. The State sought a temporary restraining order and an injunction to halt construction activities since it alleged that the defendants failed to install measures to minimize damage to the environment and to follow requirements for the pipelines storm water permit and appropriate storm water plan.We have entered into a settlement agreement with the State that dismisses the suit and assesses a fine of approximately $0.2 million. The CDPHE, through its Air Pollution Control Division, has proposed a Compliance Order on Consent with Enterprise Gas Processing, L.L.C for alleged violations of the Colorado Air Pollution and Prevention and Control Act (Colorado Act) with respect to operations of the Meeker Gas Processing Plant.The Compliance Order proposes an administrative fine of approximately $0.3 million and would require the Meeker Gas Processing Plant to be operated in compliance with the Colorado Act.We have entered into discussions regarding the terms of the Compliance Order. In January 2009, the State of New Mexico filed suit in District Court in Santa Fe County, New Mexico, under the New Mexico Air Quality Control Act. The lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon Oil Corp. (Marathon) as operator of the Indian Basin natural gas processing facility located in Eddy County, New Mexico.We own a 42.4% undivided interest in the assets comprising the Indian Basin facility.The State alleges violations of its air laws.Marathon agreed to a Consent Decree with the State which was approv |
Significant Risks and Uncertain
Significant Risks and Uncertainties | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Significant Risks and Uncertainties | Note 15.Significant Risks and Uncertainties Insurance-Related Risks We participate as a named insured in EPCOs insurance program, which provides us with property damage, business interruption and other coverages, the scope and amounts of which are customary and sufficient for the nature and extent of our operations.While we believe EPCO maintains adequate insurance coverage on our behalf, insurance will not cover every type of damage or interruption that might occur.If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position, results of operations and cash flows.In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for our repair costs or lost income.Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to our partners and, accordingly, adversely affect the market price of our common units. The following table summarizes proceeds we received from weather-related business interruption and property damage insurance claims during the periods indicated: For the Three Months Ended March 31, 2010 2009 Business interruption proceeds: Hurricane Ike $ 1.1 $ -- Total business interruption proceeds 1.1 -- Property damage proceeds: (1) Hurricane Katrina -- 23.2 Hurricane Rita 26.8 -- Hurricane Ike 1.9 -- Total property damage proceeds 28.7 23.2 Total $ 29.8 $ 23.2 (1) Our operating income for the three months ended March 31, 2010 and 2009 includes $7.6 million and $0.6 million, respectively, of proceeds from property damage insurance claims. At March 31, 2010, we had $33.8 million of estimated property damage claims outstanding related to storms that we believe are probable of collection during the next twelve months.To the extent we estimate the dollar value of such damages, a change in our estimates may occur as additional information becomes available. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Supplemental Cash Flow Information | Note 16.Supplemental Cash Flow Information The following table provides information regarding the net effect of changes in our operating assets and liabilities for the periods indicated: For the Three Months Ended March 31, 2010 2009 Decrease (increase) in: Accounts and notes receivable trade $ 43.4 $ 152.0 Accounts receivable related party 11.9 11.9 Inventories (279.1 ) (157.0 ) Prepaid and other current assets (55.5 ) 11.6 Other assets 0.6 (33.8 ) Increase (decrease) in: Accounts payable trade 118.4 (15.9 ) Accounts payable related party (21.9 ) (10.6 ) Accrued product payables 302.5 (85.2 ) Accrued expenses (29.3 ) 12.9 Accrued interest (54.2 ) (29.3 ) Other current liabilities 40.6 (0.2 ) Other liabilities (3.3 ) (2.2 ) Net effect of changes in operating accounts $ 74.1 $ (145.8 ) |
Condensed Consolidating Financi
Condensed Consolidating Financial Information | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Condensed Consolidating Financial Information | Note 17.Condensed Consolidating Financial Information EPO conducts substantially all of our business. Currently, we have no independent operations and no material assets outside those of EPO.EPO consolidates the financial statements of Duncan Energy Partners with those of its own. EPO has issued publicly traded debt securities.Enterprise Products Partners L.P., as the parent company of EPO, guarantees the debt obligations of EPO, with the exception of Duncan Energy Partners debt obligations.If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation.EPOs consolidated subsidiaries have no significant restrictions on their ability to pay distributions or make loans to Enterprise Products Partners L.P.See Note 9 for additional information regarding our consolidated debt obligations. Immediately after the closing of the TEPPCO Merger, Enterprise Products Partners L.P. contributed its ownership interests in TEPPCO and TEPPCO GP to EPO.The following condensed consolidating financial information for EPO has been recast to include TEPPCO and TEPPCO GP using the same basis of presentation described in Note 1 for our consolidated financial statements. Enterprise Products Partners L.P. Unaudited Condensed Consolidating Balance Sheet March 31, 2010 EPO and Subsidiaries Subsidiary Issuer (EPO) Other Subsidiaries (Non-guarantor) EPO and Subsidiaries Eliminations and Adjustments Consolidated EPO and Subsidiaries Parent Company (Guarantor) Eliminations and Adjustments Consolidated Total ASSETS Current assets: Cash and cash equivalents $ 70.3 $ 68.8 $ (4.4 ) $ 134.7 $ -- $ 0.2 $ 134.9 Restricted Cash 99.1 2.6 -- 101.7 -- -- 101.7 Accounts and notes receivable, net 758.7 2,370.8 (44.0 ) 3,085.5 (2.6 ) -- 3,082.9 Inventories 788.6 204.8 (2.5 ) 990.9 - -- 990.9 Prepaid and other current assets 195.3 108.6 (7.3 ) 296.6 0.2 -- 296.8 Total current assets 1,912.0 2,755.6 (58.2 ) 4,609.4 (2.4 ) 0.2 4,607.2 Property, plant and equipment, net 1,429.7 16,315.8 (10.2 ) 17,735.3 -- -- 17,735.3 Investments in unconsolidated affiliates 18,706.4 5,898.1 (23,721.0 ) 883.5 9,884.6 (9,884.6 ) 883.5 Intangible assets, net 165.8 884.7 (15.3 ) 1,035.2 -- -- 1,035.2 Goodwill 473.7 1,544.6 -- 2,018.3 -- -- 2,018.3 Other assets 255.7 123.8 (158.9 ) 220.6 -- 1.0 221.6 Total assets $ 22,943.3 $ 27,522.6 $ (23,963.6 ) $ 26,502.3 $ 9,882.2 $ (9,883.4 ) $ 26,501.1 LIABILITIES AND EQUITY Current liabilities: Current maturities of debt $ -- $ 183.9 $ (8.9 ) $ 175.0 $ -- $ -- $ 175.0 Accounts payable 214.7 426.8 (174.8 ) 466.7 0.1 -- 466.8 Accrued product payables 1,891.1 1,832.8 (28.8 ) 3,695.1 -- -- 3,695.1 Other current liabilities 360.5 246.5 (3.3 ) 603.7 -- 0.1 603.8 Total current liabilities 2 |
Subsequent Events
Subsequent Events | |
3 Months Ended
Mar. 31, 2010 | |
Notes To Financial Statements [Abstract] | |
Subsequent Events | Note 18.Subsequent Events Enterprise Products Partners Issues 13,800,000 Common Units In April 2010, we issued 13,800,000 common units (including an over-allotment of 1,800,000 common units) to the public at an offering price of $35.55 per unit.We used the net cash proceeds of approximately $485.2 million (including a net capital contribution of approximately $9.7 million from EPGP to maintain its 2% general partner interest) to pay a portion of our announced acquisition of assets from M2 Midstream LLC (Momentum) and for general partnership purposes. Acquisition of Natural Gas Gathering Systems in Haynesville Shale Area from Momentum On May 4, 2010, we purchased two natural gas gathering and treating systems from subsidiaries of Momentum for approximately $1.2billion in cash.These systems are located in northwest Louisiana and east Texas and gather natural gas produced from the Haynesville/Bossier Shales and the Cotton Valley and Taylor Sands formations.We used a portion of the proceeds from our April 2010 underwritten equity offering, together with borrowings under EPOs Multi-Year Revolving Credit Facility, to pay for this acquisition.Given the recent nature of this transaction, we have not yet completed the related purchase price allocation.These systems will be integrated into our Onshore Natural Gas Pipelines Services business segment and complement our existing assets. |
Document Information
Document Information | |
3 Months Ended
Mar. 31, 2010 | |
Document Information [Text Block] | |
Document Type | 10-Q |
Document Period End Date | 2010-03-31 |
Amendment Flag | false |
Entity Information
Entity Information | ||
3 Months Ended
Mar. 31, 2010 | May. 03, 2010
| |
Entity [Text Block] | ||
Entity Registrant Name | Enterprise Products Partners L P | |
Entity Central Index Key | 0001061219 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well Known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 634,754,083 | |
Document Fiscal Year Focus | 2,010 | |
Document Fiscal Period Focus | Q1 |