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Cash and cash equivalents

$ 74.4

$ 56.9

Restricted cash

0.0

65.6

Accounts receivable - trade, net of allowance for doubtful accounts of $13.9 at December 31, 2014 and $7.5 at December 31, 2013

3,823.0

5,475.5

2.8

6.8

1,014.2

1,093.1

576.3

325.5

5,490.7

7,023.4

29,881.6

26,946.6

Intangible assets, net of accumulated amortization of $1,246.3 at December 31, 2014 and $1,150.0 at December 31, 2013

3,042.0

2,437.1

4,302.1

1,462.2

Goodwill (see Note 11)

4,199.9

2,080.0

184.4

189.4

47,100.7

40,138.7

Current maturities of debt (see Note 12)

^[1]

2,206.4

1,125.0

773.8

723.7

118.9

150.5

3,853.3

5,608.7

335.5

304.3

585.8

326.5

Long-term debt (see Note 12)

7,873.7

8,238.7

19,157.4

16,226.5

66.6

60.8

Commitments and contingencies (see Note 18)

310.8

172.3

Limited partners:

Limited partners' equity

18,304.8

15,573.8

Accumulated other comprehensive loss

(241.6)

(359.0)

Total partners' equity

18,063.2

15,214.8

1,629.0

225.6

19,692.2

15,440.4

Summary of Significant Accounting Policies [Abstract]

$ 47,100.7

$ 40,138.7

[1]	We expect to refinance the current maturities of our debt obligations at or prior to their maturity.

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Allowance for doubtful accounts	$ 13.9	$ 7.5
Accumulated amortization	$ 1,246.3	$ 1,150.0
Limited partners:
Capital account, units outstanding (in units)	1,937,324,817	1,871,370,016

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Third parties	$ 47,879.7	$ 47,661.1	$ 42,509.8
Related parties	71.5	65.9	73.3
Total revenues (see Note 14)	47,951.2	47,727.0	42,583.1
Operating costs and expenses:
Third parties	43,228.4	43,300.8	38,602.2
Related parties	992.1	937.9	765.7
Total operating costs and expenses	44,220.5	44,238.7	39,367.9
General and administrative costs:
Third parties	83.7	74.0	78.9
Related parties	130.8	114.3	91.4
Total general and administrative costs	214.5	188.3	170.3
Total costs and expenses (see Note 14)	44,435.0	44,427.0	39,538.2
Equity in income of unconsolidated affiliates	259.5	167.3	64.3
Operating income	3,775.7	3,467.3	3,109.2
Other income (expense):
Interest expense	(921.0)	(802.5)	(771.8)
Interest income	1.3	0.9	0.8
Other, net	0.6	(1.1)	72.6
Total other expense, net	(919.1)	(802.7)	(698.4)
Income before income taxes	2,856.6	2,664.6	2,410.8
Benefit from (provision for) income taxes (see Note 16)	(23.1)	(57.5)	17.2
Net income	2,833.5	2,607.1	2,428.0
Net income attributable to noncontrolling interests (see Note 13)	(46.1)	(10.2)	(8.1)
Net income attributable to limited partners	$ 2,787.4	$ 2,596.9	$ 2,419.9
Earnings per unit: (see Note 17)
Basic earnings per unit (in dollars per unit)	$ 1.51	$ 1.45	$ 1.40
Diluted earnings per unit (in dollars per unit)	$ 1.47	$ 1.41	$ 1.35

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 2,833.5	$ 2,607.1	$ 2,428.0
Commodity derivative instruments:
Changes in fair value of cash flow hedges	161.3	(46.9)	17.3
Reclassification of losses (gains) to net income	(76.7)	22.1	14.2
Interest rate derivative instruments:
Changes in fair value of cash flow hedges	0.0	6.6	(70.2)
Reclassification of losses to net income	32.4	29.2	16.2
Total cash flow hedges	117.0	11.0	(22.5)
Other	0.4	0.4	3.5
Total other comprehensive income (loss)	117.4	11.4	(19.0)
Comprehensive income	2,950.9	2,618.5	2,409.0
Comprehensive income attributable to noncontrolling interests	(46.1)	(10.2)	(8.1)
Comprehensive income attributable to limited partners	$ 2,904.8	$ 2,608.3	$ 2,400.9

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities:
Net income	$ 2,833.5	$ 2,607.1	$ 2,428.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,360.5	1,217.6	1,104.9
Non-cash asset impairment charges (see Note 6)	34.0	92.6	63.4
Equity in income of unconsolidated affiliates	(259.5)	(167.3)	(64.3)
Distributions received from unconsolidated affiliates	375.1	251.6	116.7
Net gains attributable to asset sales and insurance recoveries (see Note 20)	(102.1)	(83.3)	(86.4)
Deferred income tax expense (benefit)	6.1	37.9	(66.2)
Changes in fair market value of derivative instruments	30.6	1.4	(29.5)
Net effect of changes in operating accounts (see Note 20)	(108.2)	(97.6)	(582.5)
Other operating activities	(7.8)	5.5	6.8
Net cash flows provided by operating activities	4,162.2	3,865.5	2,890.9
Investing activities:
Capital expenditures	(2,892.9)	(3,408.2)	(3,621.9)
Contributions in aid of construction costs	28.9	26.0	23.4
Decrease (increase) in restricted cash	65.6	(61.3)	34.2
Cash used for business combinations, net of cash received	(2,416.8)	0.0	0.0
Investments in unconsolidated affiliates	(722.4)	(1,094.1)	(609.5)
Proceeds from asset sales and insurance recoveries (see Note 20)	145.3	280.6	1,198.8
Other investing activities	(5.6)	(0.5)	(43.8)
Cash used in investing activities	(5,797.9)	(4,257.5)	(3,018.8)
Financing activities:
Borrowings under debt agreements	18,361.1	13,852.8	8,363.1
Repayments of debt	(14,341.1)	(12,680.6)	(6,676.4)
Debt issuance costs	(41.2)	(23.7)	(21.5)
Monetization of interest rate derivative instruments (see Note 6)	27.6	(168.8)	(147.8)
Cash distributions paid to limited partners (see Note 13)	(2,638.1)	(2,400.3)	(2,178.6)
Cash payments made in connection with distribution equivalent rights	(3.7)	0.0	0.0
Cash distributions paid to noncontrolling interests (see Note 13)	(48.6)	(8.9)	(13.3)
Cash contributions from noncontrolling interests (see Note 13)	4.0	115.4	6.6
Net cash proceeds from the issuance of common units	388.8	1,792.0	816.8
Other financing activities	(55.6)	(45.1)	(24.7)
Cash provided by financing activities	1,653.2	432.8	124.2
Net change in cash and cash equivalents	17.5	40.8	(3.7)
Cash and cash equivalents, January 1	56.9	16.1	19.8
Cash and cash equivalents, December 31	$ 74.4	$ 56.9	$ 16.1

STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]	Limited Partners [Member]
Balance at Dec. 31, 2011	$ 12,219.3	$ (351.4)	$ 105.9	$ 12,464.8
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,428.0	0.0	8.1	2,419.9
Cash distributions paid to limited partners	(2,178.6)	0.0	0.0	(2,178.6)
Cash distributions paid to noncontrolling interests	(13.3)	0.0	(13.3)	0.0
Cash contributions from noncontrolling interests	6.6	0.0	6.6	0.0
Net cash proceeds from the issuance of common units	816.8	0.0	0.0	816.8
Amortization of fair value of equity-based awards	58.9	0.0	0.0	58.9
Cash flow hedges	(22.5)	(22.5)	0.0	0.0
Other	(19.2)	3.5	1.0	(23.7)
Balance at Dec. 31, 2012	13,296.0	(370.4)	108.3	13,558.1
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,607.1	0.0	10.2	2,596.9
Cash distributions paid to limited partners	(2,400.3)	0.0	0.0	(2,400.3)
Cash distributions paid to noncontrolling interests	(8.9)	0.0	(8.9)	0.0
Cash contributions from noncontrolling interests	115.4	0.0	115.4	0.0
Net cash proceeds from the issuance of common units	1,792.0	0.0	0.0	1,792.0
Amortization of fair value of equity-based awards	72.4	0.0	0.0	72.4
Cash flow hedges	11.0	11.0	0.0	0.0
Other	(44.3)	0.4	0.6	(45.3)
Balance at Dec. 31, 2013	15,440.4	(359.0)	225.6	15,573.8
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	2,833.5	0.0	46.1	2,787.4
Cash distributions paid to limited partners	(2,638.1)	0.0	0.0	(2,638.1)
Cash payments made in connection with distribution equivalent rights	(3.7)	0.0	0.0	(3.7)
Cash distributions paid to noncontrolling interests	(48.6)	0.0	(48.6)	0.0
Cash contributions from noncontrolling interests	4.0	0.0	4.0	0.0
Common units issued and noncontrolling interests acquired in connection with Step 1 of Oiltanking acquisition	3,568.7	0.0	1,397.2	2,171.5
Net cash proceeds from the issuance of common units	388.8	0.0	0.0	388.8
Amortization of fair value of equity-based awards	87.0	0.0	5.2	81.8
Cash flow hedges	117.0	117.0	0.0	0.0
Other	(56.8)	0.4	(0.5)	(56.7)
Balance at Dec. 31, 2014	$ 19,692.2	$ (241.6)	$ 1,629.0	$ 18,304.8

Partnership Operations, Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2014
Partnership Operations, Organization and Basis of Presentation [Abstract]
Partnership Operations, Organization and Basis of Presentation	Note 1. Partnership Operations, Organization and Basis of Presentation General We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange ("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 and are now a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States ("U.S."), Canada and Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminals (including liquefied petroleum gas or "LPG"); crude oil gathering, transportation, storage and terminals; offshore production platforms; petrochemical and refined products transportation, storage and terminals, and related services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems and in the Gulf of Mexico. Our assets include approximately 51,300 miles of onshore and offshore pipelines; 225 million barrels ("MMBbls") of storage capacity for NGLs, petrochemicals, refined products and crude oil; and 14 billion cubic feet ("Bcf") of natural gas storage capacity. In addition, our asset portfolio includes 24 natural gas processing plants, 22 NGL and propylene fractionators, six offshore hub platforms located in the Gulf of Mexico, a butane isomerization complex, NGL import and LPG export terminals, a refined products export terminal and octane enhancement and high-purity isobutylene production facilities. We have five reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services. We conduct substantially all of our business through EPO and are owned 100% by our limited partners from an economic perspective. Enterprise GP manages our partnership and owns a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the "ASA") or by other service providers. See Note 15 for information regarding the ASA and other related party matters. As a result of our acquisition of Oiltanking GP on October 1, 2014, we began consolidating the financial statements of Oiltanking and its general partner as of the acquisition date. See Note 10 for information regarding this acquisition. See Note 13 for information regarding a two-for-one common unit split completed on August 21, 2014. All per unit amounts and number of units outstanding in these Consolidated Financial Statements and Notes thereto are presented on a post-split basis.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies

Note 2. Summary of Significant Accounting Policies

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts, including those related to natural gas imbalances. Our procedure for estimating the allowance for doubtful accounts is based on: (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses.

The following table presents our allowance for doubtful accounts activity for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Balance at beginning of period	$	7.5		$	13.2		$	13.4
Charged to costs and expenses		8.4			2.1			0.3
Deductions (1)		(2.0	)		(7.8	)		(0.5	)
Balance at end of period	$	13.9		$	7.5		$	13.2

(1) The 2013 deduction is primarily due to the write-off of certain amounts attributable to companies in bankruptcy and amounts we believe are no longer collectible.

See "Credit Risk Due to Industry Concentrations" in Note 19 for additional information.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.

Consolidation Policy

Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 13 for information regarding noncontrolling interests.

If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee's operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee's operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts.

We account for investments using the cost method when our ownership interest in an entity does not provide us with significant influence or when we have virtually no influence over the investee's operating and financial policies. At December 31, 2014, we did not have any significant investments accounted for using the cost method.

Contingencies

Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 18 for additional information regarding our contingencies.

Current Assets and Current Liabilities

We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and liabilities, respectively.

We use derivative instruments such as futures, swaps, options, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates, foreign currencies and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether similarly forecasted transactions are probable of occurring in the future.

For certain physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future. See Note 6 for additional information regarding our derivative instruments.

Earnings Per Unit

Earnings per unit is based on the amount of net income available to common unitholders and the weighted-average number of common units outstanding during a period. See Note 17 for additional information regarding our earnings per unit amounts.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management's best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2014, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable.

The following table presents the activity of our environmental reserves for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Balance at beginning of period	$	9.9		$	13.7		$	12.3
Charged to costs and expenses		11.9			3.9			13.9
Acquisition-related additions and other		2.5			0.7			5.2
Deductions		(8.7	)		(8.4	)		(17.7	)
Balance at end of period	$	15.6		$	9.9		$	13.7

At December 31, 2014 and 2013, $8.1 million and $6.0 million, respectively, of our environmental reserves were classified as current liabilities.

Equity-based Awards

See Note 5 for information regarding our accounting for equity-based awards.

Estimates

Preparing our consolidated financial statements in conformity with U.S. generally accepted accounting principles ("GAAP") requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.

Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.

Impairment Testing for Goodwill

Our goodwill amounts are assessed for impairment on a routine annual basis or when impairment indicators are present. If such indicators occur (e.g., the loss of a significant customer or technological obsolescence of assets), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its carrying value. If the fair value of the reporting unit is less than its carrying value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. See Note 11 for additional information regarding goodwill.

Impairment Testing for Long-Lived Assets

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset's carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset's carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note 6 for information regarding impairment charges related to long-lived assets during 2014, 2013 and 2012.

Impairment Testing for Unconsolidated Affiliates

We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity's industry. In the event we determine that the loss in value of an investment is an other than temporary decline, we record a charge to equity earnings to adjust the carrying value of the investment to its estimated fair value. There were no impairment charges in 2014 and 2012 related to our equity method investments. See Note 9 for information regarding our equity method investments and related impairment charge recorded during 2013.

Income Taxes

Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in qualifying income (as that term is defined in the IRS Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2014, 2013 and 2012 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Net earnings for financial statement purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner's individual tax basis in our limited partner interests. See Note 16 for additional information regarding our income taxes.

Inventories

Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of average cost or market. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 7 for additional information regarding our inventories.

Other Non-Operating Income

The following table presents the components of "Other, net" as presented on our Statements of Consolidated Operations for the periods indicated:

	For the Year Ended December 31,
	2014		2013			2012
Gain on sales of available-for-sale securities of Energy Transfer Equity (1)	$	--	$	--		$	68.8
Other		0.6		(1.1	)		3.8
Total	$	0.6	$	(1.1	)	$	72.6

(1) See Note 9 for information regarding the liquidation of our investment in limited partnership units of Energy Transfer Equity.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period.

We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.

In general, depreciation is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. With respect to midstream energy assets such as natural gas gathering systems that are reliant upon a specific natural resource basin for throughput volumes, the anticipated useful economic life of such assets may be limited by the estimated life of the associated natural resource basin from which the assets derive benefit. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes.

Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms.

Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any. See Note 8 for additional information regarding our property, plant and equipment.

Certain of our plant operations entail periodic planned outages for major maintenance activities. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items. We use the expense-as-incurred method for our planned major maintenance activities for plant operations; however, the cost of annual planned major maintenance projects for such plants are deferred and recognized ratably until the next planned annual outage. With regard to the planned major maintenance activities on our marine transportation assets and underground storage caverns, we use the deferral method to account for such costs. Under this method, major maintenance costs are capitalized and amortized over the period until the next major overhaul or cavern integrity project.

Asset retirement obligations ("AROs") are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.

Restricted Cash

Restricted cash represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, crude oil, refined products and NGLs. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or deposit requirements change. At December 31, 2013, our restricted cash amount was $65.6 million. We did not have any restricted cash as of December 31, 2014. See Note 6 for information regarding our derivative instruments and hedging activities.

Revenue Recognition

In general, we recognize revenue from our customers when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer's price is fixed or determinable and (iv) collectibility is reasonably assured. Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue. See Note 4 for information regarding our revenue recognition policies.

Recent Accounting Developments

12 Months Ended

Dec. 31, 2014

Recent Accounting Developments [Abstract]

Recent Accounting Developments

Note 3. Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board and the International Accounting Standards Board finished their joint project to converge U.S. GAAP and International Financial Reporting Standards in the area of revenue recognition. The resulting accounting standards update eliminates the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replaces it with a principles based approach for determining revenue recognition.

The core principle in the new guidance is that a company should recognize revenue in a manner that depicts the transfer of goods or services to customers in an amount that reflects the consideration the company expects to receive for those goods or services. In order to apply this core principle, companies will apply the following five steps in determining the amount of revenues to recognize:

identify the contract;

identify the performance obligations in the contract;

determine the transaction price;

allocate the transaction price to the performance obligations in the contract; and

recognize revenue when (or as) the performance obligation is satisfied.

Each of these steps involves judgment and an analysis of the contract's terms and conditions.

We are continuing to evaluate this recently issued accounting guidance; therefore, we are currently not in a position to estimate its impact on our consolidated financial statements. The effective date of the new standard is January 1, 2017. At present, we expect to adopt the new standard using the modified retrospective method. This modified approach allows us to apply the new standard to (i) all new contracts after the effective date and (ii) all existing contracts as of the effective date through a cumulative adjustment to equity. Consolidated revenues for periods prior to the effective date would not be retrospectively adjusted.

Revenue Recognition	12 Months Ended
Revenue Recognition	Dec. 31, 2014
Revenue Recognition [Abstract]
Revenue Recognition	Note 4. Revenue Recognition The following information summarizes our revenue recognition policies by business segment. See Note 14 for general information regarding our business segments. NGL Pipelines & Services In our natural gas processing business, we utilize contracts that are either fee-based, commodity-based or a combination of the two. When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer's natural gas has been processed and redelivered. Our commodity-based contracts include keepwhole and margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts and contracts featuring a combination of commodity and fee-based terms. Under keepwhole and margin-band contracts, we take ownership of mixed NGLs extracted from the producer's natural gas stream while replacing the equivalent quantity of energy on a natural gas basis to producers. We recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. Under percent-of-liquids contracts, we take ownership of a portion of the mixed NGLs extracted from the producer's natural gas stream (in lieu of a cash processing fee) and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. Under percent-of-proceeds contracts, we share in the proceeds generated from the sale of mixed NGLs we extract on the producer's behalf (in lieu of a cash processing fee). In certain cases, we also utilize contracts that include a combination of commodity-based terms (such as those described above) and fee-based terms. Our NGL marketing activities generate revenues from merchant activities such as term and spot sales of NGLs, which we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and contract purchases. Revenue from these sales contracts is recognized when the NGLs are delivered to customers. In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as location, timing or NGL product quality. NGL sales contracts associated with our export facilities may also include take-or-pay provisions. Revenues from NGL pipeline transportation contracts and tariffs are generally based upon a fixed fee per gallon of liquids transported multiplied by the volume delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission ("FERC"), or contractual arrangements. Typically, pipeline transportation revenue is recognized when volumes are transported and delivered. However, under certain NGL pipeline transportation agreements (e.g., those associated with committed shippers on our Texas Express Pipeline, Front Range Pipeline, ATEX and Aegis Ethane Pipeline) customers are required to ship a minimum volume over an agreed-upon period. These arrangements typically entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper "make-up rights"). Revenue pursuant to such agreements, including that associated with make-up rights, is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation. We collect storage revenue under our NGL and related product storage contracts primarily from capacity reservation agreements, where we collect a fee for reserving storage capacity for customers in our underground storage wells. Customers pay reservation fees based on the level of storage capacity reserved rather than the actual volumes stored. Under these agreements, revenue is recognized ratably over the specified reservation period. When a customer exceeds its reserved capacity, we charge that customer excess storage fees, which are recognized in the period of occurrence. In addition, we generally charge customers throughput fees based on volumes delivered into and subsequently withdrawn from storage, which are recognized as the service is provided. We typically earn revenues from NGL fractionation under fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., natural gas fuel costs). Under fee-based arrangements, revenue is recognized in the period services are provided. At our Norco facility in Louisiana, we perform fractionation services for certain customers under percent-of-liquids contracts. Such contracts allow us to retain a contractually determined percentage of the customer's fractionated NGLs as payment for services rendered. Revenue is recognized from such arrangements when we sell and deliver the retained NGLs to customers. Revenue from NGL import and LPG export terminaling activities is recorded in the period services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded. Onshore Natural Gas Pipelines & Services Our onshore natural gas pipelines typically generate revenues from transportation agreements under which shippers are billed a fee per unit of volume transported multiplied by the volume gathered or delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. Certain of our onshore natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved (whether or not the shipper actually utilizes such capacity). Revenues are recognized when volumes have been delivered to customers or in the period we provide firm capacity reservation services. Under our natural gas storage revenue contracts, there are typically two components: (i) monthly demand payments, which are associated with a customer's storage capacity reservation and paid regardless of actual usage, and (ii) storage fees per unit of volume stored at our facilities. Revenue from demand payments is recognized during the period the customer reserves capacity. Revenue from storage fees is recognized in the period the services are provided. Our natural gas marketing activities generate revenue from the sale and delivery to local gas distribution companies and other customers of natural gas purchased from producers, regional natural gas processing plants and the open market. Revenue from these sales contracts is recognized when natural gas is delivered to customers. In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location. Onshore Crude Oil Pipelines & Services Revenue from crude oil transportation is generally based upon a fixed fee per barrel transported multiplied by the volume delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. Typically, revenue associated with these arrangements is recognized when volumes are transported and delivered; however, under certain of our crude oil pipeline transportation agreements, customers are required to ship a minimum volume over an agreed-upon period, with make-up rights. Revenue pursuant to such agreements, including that associated with make-up rights, is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation. Under our crude oil terminaling agreements, we charge customers for crude oil storage based on storage capacity reservation agreements, where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized ratably over the specified reservation period. In addition, we charge our customers throughput (or "pumpover") fees based on volumes withdrawn from our terminals. Revenue is also generated from fee-based trade documentation services and is recognized as services are completed. Our crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or from others on the open market. These sales contracts generally settle with the physical delivery of crude oil to customers. In general, the sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location, timing or crude oil quality. Offshore Pipelines & Services Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume gathered or transported multiplied by the volume delivered. Transportation fees are based either on contractual arrangements or tariffs regulated by the FERC. Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered. Revenues from offshore platform services generally consist of demand fees and commodity charges. Revenues from offshore platform services are recognized in the period the services are provided. Demand fees represent charges to customers served by our offshore platforms regardless of the volume the customer actually delivers to the platform. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform multiplied by the total volume of each product delivered. Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers. Petrochemical & Refined Products Services Our propylene fractionation, butane isomerization and deisobutanizer facilities generate revenue through fee-based arrangements, which typically include a base-processing fee subject to adjustment for changes in power, fuel and labor costs, all of which are the primary costs of propylene fractionation and butane isomerization. Our butane isomerization and deisobutanizer operations also generate revenue from the sale and delivery of by-products. Revenue resulting from such agreements is recognized in the period the services are provided. Revenues from our petrochemical pipeline transportation contracts are primarily based upon a fixed fee per volume transported (typically measured in gallons or pounds) multiplied by the volume delivered. Our petrochemical marketing activities include the purchase and fractionation of refinery grade propylene obtained in the open market and generate revenues from the sale and delivery of products obtained through propylene fractionation. Revenue from these sales contracts is recognized when such products are delivered to customers. In general, we sell our petrochemical products at market-based prices, which may include pricing differentials for factors such as delivery location. Revenue from the production and sale of octane additives and high purity isobutylene is dependent on the sales price and volume of such commodities sold to customers. Revenue is recognized for sales transactions when the product is delivered. Pipelines transporting refined products generate revenues through contracts and tariffs as customers are billed a fixed fee per barrel of liquids transported multiplied by the volume delivered. The fees charged under these arrangements are either contractual or regulated by governmental agencies, including the FERC. Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered. Revenue from our refined products storage facilities is based on capacity reservation agreements where we collect a fee for reserving a defined storage capacity for customers at our facilities. Under these contracts, revenue is recognized ratably over the length of the storage period. Revenue from product terminaling activities is recorded in the period such services are provided. Customers are typically billed a fee per unit of volume loaded. Revenue is also generated from the provision of inland and offshore marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil, liquefied petroleum gas and other petroleum products via tow boats and tank barges. Under our marine services transportation contracts, revenue is recognized over the transit time of individual tows as determined on an individual contract basis, which is generally less than ten days in duration. Revenue from these contracts is typically based on set day rates or a set fee per cargo movement. The costs of fuel, substantially all of which is a pass through expense, and other specified operational fees and costs are directly reimbursed by the customer under most of these contracts.

Equity-based Awards

12 Months Ended

Dec. 31, 2014

Equity-based Awards [Abstract]

Equity-based Awards

Note 5. Equity-based Awards

An allocated portion of the fair value of EPCO's equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Equity-classified awards:
Restricted common unit awards	$	42.1	$	71.5	$	57.0
Unit option awards		--		0.8		1.3
Phantom unit awards		45.1		--		--
Liability-classified awards		0.3		0.5		1.7
Total	$	87.5	$	72.8	$	60.0

The fair value of equity-classified awards is amortized into earnings over the requisite service or vesting period. Equity-classified awards are expected to result in the issuance of common units upon vesting. Compensation expense for liability-classified awards is recognized over the requisite service or vesting period based on the fair value of the award remeasured at each reporting date. Liability-classified awards are settled in cash upon vesting.

At December 31, 2014, EPCO's significant long-term incentive plans applicable to us were the Enterprise Products 1998 Long-Term Incentive Plan ("1998 Plan") and the 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) ("2008 Plan").

The 1998 Plan provides for awards of our common units and other rights to our non-employee directors and to employees of EPCO and its affiliates providing services to us. Awards under the 1998 Plan may be granted in the form of unit options, restricted common units, phantom units and distribution equivalent rights ("DERs"). Up to 14,000,000 of our common units may be issued as awards under the 1998 Plan. After giving effect to awards granted under the 1998 Plan through December 31, 2014, a total of 2,748,017 additional common units could be issued.

The 2008 Plan (as amended and restated) is a long-term incentive plan under which any employee or consultant of EPCO, us or our affiliates that provides services to us, directly or indirectly, may receive incentive compensation awards in the form of options, restricted common units, phantom units, DERs, unit appreciation rights ("UARs"), unit awards, other unit-based awards or substitute awards. Non-employee directors of our general partner may also participate in the 2008 Plan.

The maximum number of common units available for issuance under the 2008 Plan was 25,000,000 at December 31, 2014. This amount automatically increased under the terms of the 2008 Plan by 5,000,000 common units on January 1, 2015 and will continue to automatically increase annually on January 1 thereafter during the term of the 2008 Plan; provided, however, that in no event shall the maximum aggregate number exceed 70,000,000 common units. The 2008 Plan is effective until September 30, 2023 or, if earlier, until the time that all available common units under the 2008 Plan have been delivered to participants or the time of termination of the 2008 Plan by the Board of Directors of EPCO or by the Audit and Conflicts Committee. After giving effect to awards granted under the 2008 Plan through December 31, 2014, a total of 12,895,605 additional common units could be issued.

Restricted Common Unit Awards

Restricted common unit awards allow recipients to acquire our common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. Restricted common unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire. Restricted common units are included in the number of common units outstanding as presented on our Consolidated Balance Sheets.

The fair value of a restricted common unit award is based on the market price per unit of our common units on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

The following table presents information regarding restricted common unit awards for the periods indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at December 31, 2011		7,736,432		$	17.11
Granted (2)		3,177,476		$	25.98
Vested		(2,633,206	)	$	17.40
Forfeited		(493,730	)	$	20.21
Restricted common units at December 31, 2012		7,786,972		$	20.43
Granted (3)		3,549,052		$	28.61
Vested		(3,770,696	)	$	17.48
Forfeited		(344,114	)	$	23.82
Restricted common units at December 31, 2013		7,221,214		$	25.83
Vested		(2,634,074	)	$	23.94
Forfeited		(357,350	)	$	26.38
Restricted common units at December 31, 2014		4,229,790		$	26.96

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued during 2012 was $82.5 million based on a grant date market price of our common units ranging from $25.96 to $26.77 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards. (3) The aggregate grant date fair value of restricted common unit awards issued during 2013 was $101.5 million based on a grant date market price of our common units ranging from $28.56 to $31.74 per unit. An estimated annual forfeiture rate of 3.9% was applied to these awards.

Each recipient of a restricted common unit award is entitled to nonforfeitable cash distributions equal to the product of the number of restricted common units outstanding for the participant and the cash distribution per unit paid to our common unitholders. These distributions are included in "Cash distributions paid to limited partners" as presented on our Statements of Consolidated Cash Flows.

The following table presents supplemental information regarding restricted common unit awards for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Cash distributions paid to restricted common unitholders	$	7.3	$	10.6	$	10.5
Total intrinsic value of restricted common unit awards that vested during period	$	87.1	$	109.9	$	67.0

For the EPCO group of companies, the unrecognized compensation cost associated with restricted common unit awards was an aggregate $28.3 million at December 31, 2014, of which our allocated share of the cost is currently estimated to be $24.9 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 1.5 years.

Unit Option Awards

EPCO's long-term incentive plans provide for the issuance of non-qualified incentive options denominated in our common units. When issued, the exercise price of each unit option award may be no less than the market price of our common units on the date of grant (except as otherwise provided with respect to substitute awards). In general, unit option awards have a vesting period of four years from the date of grant and expire at the end of the calendar year following the year of vesting (e.g., an option vesting on May 29, 2014 will expire on December 31, 2015). However, unit option awards only become exercisable at certain times during the calendar year following the year in which they vest (typically the months of February, May, August and November).

The fair value of each unit option award is estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions including expected life of the option, risk-free interest rates, expected distribution yield of our common units, and expected price volatility of our common units. In general, our assumption of expected life of the options represents the period of time that the options are expected to be outstanding based on an analysis of our historical option activity. Our selection of risk-free interest rates is based on published yields for U.S. government securities with terms comparable to the expected life of the option. The expected distribution yield and unit price volatility assumptions are estimated based on several factors, which include an analysis of historical price volatility and distribution yield over a period of time equal to the expected life of the option. Compensation expense recorded in connection with unit option awards is based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period.

The following table presents unit option award activity for the periods indicated:

	Number of Units			Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Unit option awards at December 31, 2011		7,506,840		$	14.04
Exercised		(1,484,560	)	$	15.39
Forfeited		(500,000	)	$	13.73
Unit option awards at December 31, 2012		5,522,280		$	13.71
Exercised		(1,472,280	)	$	14.98
Unit option awards at December 31, 2013 (2,3)		4,050,000		$	13.24
Exercised		(2,720,000	)	$	11.83
Forfeited		(60,000	)	$	16.14
Unit option awards at December 31, 2014 (2,3)		1,270,000		$	16.14		1.0	$	25.4

(1) Aggregate intrinsic value reflects fully vested unit option awards at the date indicated. (2) At December 31, 2014 and 2013, we were committed to issue 1,270,000 and 4,050,000, respectively, of our common units if all outstanding unit option awards were exercised. All of the unit option awards outstanding at December 31, 2014 vested during 2014 and became exercisable beginning in February 2015. (3) None of the unit option awards outstanding at December 31, 2014, 2013 and 2012 were exercisable as of such dates, respectively.

In order to fund its unit option award-related obligations, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit option awards, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.

The following table presents supplemental information regarding unit option awards during the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Total intrinsic value of unit option awards exercised during period	$	57.5	$	19.8	$	14.6
Cash received from EPCO in connection with the exercise of unit option awards	$	33.4	$	11.5	$	10.2
Unit option award-related cash reimbursements to EPCO	$	57.5	$	19.8	$	14.0

As of December 31, 2014, all compensation expense related to unit option awards had been recognized.

Phantom Unit Awards

Phantom unit awards allow recipients to acquire our common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. Phantom unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire.

At December 31, 2014, substantially all of our phantom unit awards are expected to result in the issuance of common units upon vesting; therefore, the applicable awards are accounted for as equity-classified awards. The fair value of a phantom unit award is based on the market price per unit of our common units on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period. These awards were first issued in February 2014.

The following table presents phantom unit award activity for the period indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Phantom unit awards at December 31, 2013		--		$	--
Granted (2)		3,530,710		$	33.12
Vested		(38,200	)	$	33.04
Forfeited		(150,120	)	$	33.12
Phantom unit awards at December 31, 2014		3,342,390		$	33.13

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of phantom unit awards issued during 2014 was $117.0 million based on a grant date market price of our common units ranging from $33.04 to $37.59 per unit. An estimated annual forfeiture rate of 3.4% was applied to these awards.

Our long-term incentive plans provide for the issuance of DERs in connection with phantom unit awards. A DER entitles the participant to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the participant and the cash distribution per common unit paid to our common unitholders. Cash payments made in connection with DERs are charged to partners' equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed.

The following table presents supplemental information regarding our phantom unit awards for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Cash payments made in connection with DERs	$	3.7	$	--	$	--
Total intrinsic value of phantom unit awards that vested during period	$	1.4	$	--	$	--

For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $58.2 million at December 31, 2014, of which our allocated share of the cost is currently estimated to be $53.1 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.

Derivative Instruments, Hedging Activities and Fair Value Measurements

12 Months Ended

Dec. 31, 2014

Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]

Derivative Instruments, Hedging Activities and Fair Value Measurements

Note 6. Derivative Instruments, Hedging Activities and Fair Value Measurements

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as 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 our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be 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) and is reclassified into earnings when the forecasted transaction affects earnings.

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 the changes in 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 not probable of occurring is immediately recognized in earnings.

Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, they are accounted for using mark-to-market accounting.

Interest Rate Hedging Activities

We may utilize interest rate swaps, forward starting swaps and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy is a component in controlling our overall cost of capital associated with such borrowings. Interest rate swaps exchange the stated interest rate paid on a notional amount of existing debt for the fixed or floating interest rate stipulated in the derivative instrument. Forward starting swaps hedge the expected underlying benchmark interest rates related to future issuances of debt.

As a result of market conditions in early October 2014, we elected to terminate all of our outstanding interest rate swaps. We terminated 10 fixed-to-floating swaps having an aggregate notional value of $750.0 million, which resulted in cash gains totaling $17.6 million. In addition, we terminated 16 fixed-to-floating swaps having a notional value of $800.0 million entered into in connection with the issuance of Senior Notes LL in October 2014 (see Note 12). The early termination of these 16 swaps resulted in cash gains totaling $10.0 million. Since both groups of swaps were accounted for as fair value hedges, the aggregate $27.6 million of gains will be carried as a component of long-term debt and amortized into earnings (as a decrease in interest expense) using the effective interest method over the remaining life of the associated debt obligations. The $17.6 million gain will be amortized through January 2016 and the $10.0 million gain will be amortized through October 2019.

In July 2014, six undesignated floating-to-fixed swaps having an aggregate notional amount of $600.0 million expired. These swaps were accounted for as mark-to-market instruments with changes in fair value recorded in "Interest expense" on our Statements of Consolidated Operations.

In connection with the issuance of senior notes during 2013, we settled 16 forward starting swaps having an aggregate notional amount of $1.0 billion, which resulted in cash losses totaling $168.8 million. As cash flow hedges, losses on these derivative instruments are a component of accumulated other comprehensive loss and are being amortized into earnings (as an increase in interest expense) over the remaining life of the associated debt obligations using the effective interest method. The $168.8 million loss will be amortized through March 2023.

During 2012, we settled 11 fixed-to-floating interest rate swaps having an aggregate notional amount of $800.0 million, resulting in gains totaling $37.7 million. As fair value hedges, the unamortized portion of these gains are a component of long-term debt and were amortized to earnings (as a decrease in interest expense) using the effective interest method over the remaining life of the associated debt through October 2014.

In connection with the issuance of senior notes during 2012, we settled 17 forward starting swaps having an aggregate notional amount of $850.0 million, resulting in cash losses totaling $185.5 million. As cash flow hedges, losses on theses derivative instruments are a component of accumulated other comprehensive loss and are being amortized to earnings (as an increase in interest expense) over the remaining life of the associated debt obligations using the effective interest method. The $185.5 million loss will be amortized through August 2022.

Commodity Hedging Activities

The prices of natural gas, NGLs, crude oil, refined products and petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps, basis swaps and option contracts. The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2014 (volume measures as noted):

	Volume (1)				Accounting
Derivative Purpose	Current (2)		Long-Term (2)		Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted sales of NGLs (MMBbls) (3)		0.9		n/a	Cash flow hedge
Natural gas marketing:
Forecasted sales of natural gas (Bcf)		1.0		n/a	Cash flow hedge
Natural gas storage inventory management activities (Bcf)		8.6		n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)		9.9		n/a	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)		10.2		n/a	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)		1.2		n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)		1.8		n/a	Cash flow hedge
Refined products inventory management activities (MMBbls)		0.2		n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)		5.8		n/a	Cash flow hedge
Forecasted sales of crude oil (MMBbls)		6.9		n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (4,5)		81.4		11.8	Mark-to-market
Crude oil risk management activities (MMBbls) (5)		4.2		n/a	Mark-to-market

(1)

Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.

(2)

The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2015, October 2015 and March 2018, respectively.

(3)

Forecasted sales of NGL volumes under natural gas processing exclude 0.1 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.

(4)

Current volumes include 35.2 Bcf of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences.

(5)

Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Our predominant commodity hedging strategies in 2014 consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities and (ii) hedging the fair value of commodity products held in inventory. The objective of our hedging program involving anticipated future commodity purchases and sales is to hedge the margins of certain transportation, storage and blending, processing and fractionation activities by locking in purchases and sales prices through the use of forward contracts and derivative instruments. The objective of our hedging program for inventory is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of forward contracts and derivative instruments.

Certain basis swaps, basis spread options and other derivative instruments not designated as hedging instruments are used to manage market risks associated with anticipated purchases and sales of commodity products. There is some uncertainty involved in the timing of these transactions often due to the development of more favorable profit opportunities or when spreads are insufficient to cover variable costs thus reducing the likelihood that the transactions will occur during the periods originally forecasted. In accordance with derivatives accounting guidance, these instruments do not qualify for hedge accounting even though they are effective at managing the risk exposures of the underlying assets. Due to volatility in commodity prices, any non-cash, mark-to-market earnings variability cannot be predicted.

Tabular Presentation of Fair Value Amounts, and Gains and Losses on

Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:

	Asset Derivatives						Liability Derivatives
	December 31, 2014			December 31, 2013			December 31, 2014			December 31, 2013
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	20.2	Other current liabilities	$	--	Other current liabilities	$	--
Interest rate derivatives	Other assets		--	Other assets		12.4	Other liabilities		--	Other liabilities		--
Total interest rate derivatives			--			32.6			--			--
Commodity derivatives	Other current assets		217.9	Other current assets		30.9	Other current liabilities		145.3	Other current liabilities		46.5
Commodity derivatives	Other assets		--	Other assets		--	Other liabilities		--	Other liabilities		0.3
Total commodity derivatives			217.9			30.9			145.3			46.8
Total derivatives designated as hedging instruments		$	217.9		$	63.5		$	145.3		$	46.8

Derivatives not designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	--	Other current liabilities	$	--	Other current liabilities	$	7.8
Commodity derivatives	Other current assets		8.1	Other current assets		7.6	Other current liabilities		0.7	Other current liabilities		5.5
Commodity derivatives	Other assets		0.6	Other assets		2.8	Other liabilities		1.4	Other liabilities		2.8
Total commodity derivatives			8.7			10.4			2.1			8.3
Total derivatives not designated as hedging instruments		$	8.7		$	10.4		$	2.1		$	16.1

Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated:

	Offsetting of Financial Assets and Derivative Assets
										Gross Amounts Not Offset in the Balance Sheet
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received			Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)							(v) = (iii) + (iv)
As of December 31, 2014:
Commodity derivatives		$	226.6		$	--		$	226.6		$	(147.3	)	$	(23.9	)		$	55.4
As of December 31, 2013:
Interest rate derivatives		$	32.6		$	--		$	32.6		$	(2.6	)	$	--			$	30.0
Commodity derivatives			41.3			--			41.3			(41.0	)		--				0.3

	Offsetting of Financial Liabilities and Derivative Liabilities
										Gross Amounts Not Offset in the Balance Sheet
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Financial Instruments				Cash Collateral Paid				Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)								(v) = (iii) + (iv)
As of December 31, 2014:
Commodity derivatives		$	147.4		$	--		$	147.4		$	(147.3	)		$	--			$	0.1
As of December 31, 2013:
Interest rate derivatives		$	7.8		$	--		$	7.8		$	(2.6	)		$	--			$	5.2
Commodity derivatives			55.1			--			55.1			(41.0	)			(9.3	)			4.8

Derivative assets and liabilities recorded on our Consolidated Balance Sheets are presented on a gross-basis and determined at the individual transaction level. This presentation method is applied regardless of whether the respective exchange clearing agreements, counterparty contracts or master netting agreements contain netting language often referred to as "rights of offset." Although derivative amounts are presented on a gross-basis, having rights of offset enable the settlement of a net as opposed to gross receivable or payable amount under a counterparty default or liquidation scenario.

Cash is paid and received as collateral under certain agreements, particularly for those associated with exchange transactions. For any cash collateral payments or receipts, corresponding assets or liabilities are recorded to reflect the variation margin deposits or receipts with exchange clearing brokers and customers. These balances are also presented on a gross-basis on our Consolidated Balance Sheets.

The tabular presentation above provides a means for comparing the gross amount of derivative assets and liabilities, excluding associated accounts payable and receivable, to the net amount that would likely be receivable or payable under a default scenario based on the existence of rights of offset in the respective derivative agreements. Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amounts associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

The following tables present the effect of our derivative instruments designated as fair value hedges on our Statements of Consolidated Operations for the periods indicated:

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Derivative
		For the Year Ended December 31,
		2014				2013				2012
Interest rate derivatives	Interest expense		$	(26.5	)		$	(13.1	)		$	2.7
Commodity derivatives	Revenue			11.9				(0.1	)			(6.4	)
Total			$	(14.6	)		$	(13.2	)		$	(3.7	)

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Year Ended December 31,
		2014				2013				2012
Interest rate derivatives	Interest expense		$	26.4			$	12.8			$	(2.9	)
Commodity derivatives	Revenue			(11.8	)			(5.7	)			19.1
Total			$	14.6			$	7.1			$	16.2

With respect to our derivative instruments designated as fair value hedges, amounts attributable to ineffectiveness and those excluded from the assessment of hedge effectiveness were not material to our consolidated financial statements during the periods presented.

The following tables present the effect of our derivative instruments designated as cash flow hedges on our Statements of Consolidated Operations and Statements of Consolidated Comprehensive Income for the periods indicated:

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative (Effective Portion)
	For the Year Ended December 31,
	2014		2013			2012
Interest rate derivatives	$	--	$	6.6		$	(70.2	)
Commodity derivatives – Revenue (1)		161.3		(47.9	)		31.0
Commodity derivatives – Operating costs and expenses (1)		--		1.0			(13.7	)
Total	$	161.3	$	(40.3	)	$	(52.9	)

(1) The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)
		For the Year Ended December 31,
		2014				2013				2012
Interest rate derivatives	Interest expense		$	(32.4	)		$	(29.2	)		$	(16.2	)
Commodity derivatives	Revenue			75.0				(22.4	)			10.1
Commodity derivatives	Operating costs and expenses			1.7				0.3				(24.3	)
Total			$	44.3			$	(51.3	)		$	(30.4	)

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)
		For the Year Ended December 31,
		2014				2013			2012
Commodity derivatives	Revenue		$	(0.3	)		$	0.2		$	--
Commodity derivatives	Operating costs and expenses			--				--			0.3
Total			$	(0.3	)		$	0.2		$	0.3

Over the next twelve months, we expect to reclassify $35.4 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $70.0 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings as an increase in revenue.

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the periods indicated:

Derivatives Not Designated as Hedging Instruments	Location	Gain (Loss) Recognized in Income on Derivative
		For the Year Ended December 31,
		2014				2013				2012
Interest rate derivatives	Interest expense		$	(0.1	)		$	(0.7	)		$	(5.6	)
Commodity derivatives	Revenue			(23.0	)			7.3				22.7
Commodity derivatives	Operating costs and expense			--				--				(2.8	)
Total			$	(23.1	)		$	6.6			$	14.3

Fair Value Measurements

Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the highest extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy.

The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange). Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations. The fair value of our interest rate derivatives are determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements.

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect management's ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed data. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of an instrument's fair value. With regards to commodity derivatives, our Level 3 fair values primarily consist of ethane, propane, normal butane and natural gasoline-based contracts with terms greater than one year and certain options used to hedge natural gas storage inventory and transportation capacities. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments.

The valuation of our Liquidity Option Agreement (see Note 18) is based on a number of Level 3 inputs including expected business term, partnership growth rates, third-party ownership interests in our limited partner units, anticipated tax strategies, forecasted yields on securities and future federal and state tax rates.

Transfers within the fair value hierarchy routinely occur for certain term contracts as prices and other inputs used for the valuation of future delivery periods become more observable with the passage of time. Other transfers are made periodically in response to changing market conditions that affect liquidity, price observability and other inputs used in determining valuations. We deem any such transfers to have occurred at the end of the quarter in which they transpired. There were no transfers between Level 1 and 2 for the years ended December 31, 2014 and 2013, respectively. See below for information related to transfers out of Level 3.

Recurring Fair Value Measurements

The following tables set forth, by level within the fair value hierarchy, the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment.

	December 31, 2014 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets:
Commodity derivatives	$	37.8	$	187.8	$	1.0	$	226.6

Financial liabilities:
Liquidity Option Agreement	$	--	$	--	$	119.4	$	119.4
Commodity derivatives		13.8		133.0		0.6		147.4
Total	$	13.8	$	133.0	$	120.0	$	266.8

	December 31, 2013 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets:
Interest rate derivatives	$	--	$	32.6	$	--	$	32.6
Commodity derivatives		17.2		20.2		3.9		41.3
Total	$	17.2	$	52.8	$	3.9	$	73.9

Financial liabilities:
Interest rate derivatives	$	--	$	7.8	$	--	$	7.8
Commodity derivatives		30.8		23.6		0.7		55.1
Total	$	30.8	$	31.4	$	0.7	$	62.9

The following table sets forth a reconciliation of changes in the fair values of our recurring Level 3 financial assets and liabilities on a combined basis for the periods indicated:

		For the Year Ended December 31,
	Location	2014			2013
Financial asset (liability) balance, net, January 1		$	3.2		$	(1.5	)
Total gains (losses) included in:
Net income (1)	Revenue		0.9			2.8
Other comprehensive income	Commodity derivative instruments – changes in fair value of cash flow hedges		(2.6	)		(0.9	)
Settlements			(3.4	)		1.6
Acquisition of Liquidity Option Agreement			(119.4	)		--
Transfers out of Level 3 (2)			2.3			1.2
Financial asset (liability) balance, net, December 31 (2)		$	(119.0	)	$	3.2

(1) There were $2.6 million and $4.4 million of unrealized losses and gains included in these amounts for the years ended December 31, 2014 and 2013, respectively. (2) Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2014 and 2013.

The following tables provide quantitative information about our recurring Level 3 fair value measurements at the dates indicated:

	Fair Value At December 31, 2014
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	1.0	$	0.4	Discounted cash flow	Forward commodity prices	$49.26-$53.27/barrel
Commodity derivatives – Natural gas		--		0.2	Discounted cash flow	Forward commodity prices	$3.05-$4.09/MMBtu
Liquidity Option Agreement (see Note 18)		--		119.4	Discounted cash flow	Expected life of OTA following option exercise	30 years
						Estimated growth rates in Enterprise's earnings before interest, taxes, depreciation and amortization	3% to 14%
						OTA ownership interest in Enterprise common units	1.9% to 2.8%
						Interest rate on assumed debt of OTA following option exercise	4.9% over 30 years
						Forecasted yield on Enterprise common units	4.0% to 5.5%
						Federal and state tax rate	38%
Total	$	1.0	$	120.0

	Fair Value At December 31, 2013
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	3.9	$	0.7	Discounted cash flow	Forward commodity prices	$89.55-$98.54/barrel

With respect to commodity derivatives, we believe forward commodity prices are the most significant unobservable inputs in determining our Level 3 recurring fair value measurements at December 31, 2014. In general, changes in the price of the underlying commodity increases or decreases the fair value of a commodity derivative depending on whether the derivative was purchased or sold. We generally expect changes in the fair value of our derivative instruments to be offset by corresponding changes in the fair value of our hedged exposures.

The Level 3 recurring fair value measurement pertaining to the Liquidity Option Agreement is based on a number of unobservable inputs. See Note 18 for a discussion of this agreement and the valuation method underlying its provisional carrying value at December 31, 2014. Subsequent changes in the fair value of this option (other than those attributable to the finalization of our purchase price allocation as discussed in Note 10) will be recorded in earnings each reporting period until the option expires or is exercised.

We have a risk management policy that covers our Level 3 commodity derivatives. Governance and oversight of risk management activities for these commodities are provided by our CEO with guidance and support from a risk management committee ("RMC") that meets quarterly (or on a more frequent basis, if needed). Members of executive management attend the RMC meetings, which are chaired by the head of our commodities risk control group. This group is responsible for preparing and distributing daily reports and risk analysis to members of the RMC and other appropriate members of management. These reports include mark-to-market valuations with the one-day and month-to-date changes in fair values. This group also develops and validates the forward commodity price curves used to estimate the fair values of our Level 3 commodity derivatives. These forward curves incorporate published indexes, market quotes and other observable inputs to the extent available.

Nonrecurring Fair Value Measurements

The following table summarizes our non-cash impairment charges by segment during each of the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
NGL Pipelines & Services	$	16.2	$	30.6	$	16.3
Onshore Natural Gas Pipelines & Services		0.7		--		29.2
Onshore Crude Oil Pipelines & Services		2.9		30.1		10.6
Offshore Pipelines & Services		5.1		18.0		4.0
Petrochemical & Refined Products Services		9.1		18.7		3.3
Total	$	34.0	$	97.4	$	63.4

Our non-cash asset impairment charges for the year ended December 31, 2014 are a component of operating costs and expenses on our Statements of Consolidated Operations and primarily relate to the abandonment of certain natural gas processing equipment in Louisiana, natural gas pipeline segments in the Gulf of Mexico, refined products terminal and pipeline assets in Arkansas, and NGL storage caverns in Oklahoma and Texas. The following table summarizes our non-recurring fair value measurements for the year ended December 31, 2014:

			Fair Value Measurements Using
	Carrying Value at December 31, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Non-Cash Impairment Loss
Impairment of long-lived assets disposed of other than by sale	$	--		$	--		$	--		$	--		$	26.7
Impairment of long-lived assets to be disposed of by sale		1.5			--			--			1.5			7.3
Total													$	34.0

Our non-cash asset impairment charges for the year ended December 31, 2013 include $4.8 million related to our investment in two offshore natural gas gathering systems owned by Neptune (see Note 9). This charge is a component of equity in income of unconsolidated affiliates on our Statements of Consolidated Operations. The remainder of the non-cash impairment charges for 2013, or $92.6 million, are a component of operating costs and expenses on our Statements of Consolidated Operations. These latter charges primarily represent the abandonment of certain crude oil and natural gas pipeline segments in Texas, Oklahoma and the Gulf of Mexico, certain refined products terminal assets in Texas, an NGL storage cavern in Arizona and an NGL fractionator and storage caverns in Ohio. The following table summarizes our non-recurring fair value measurements for the year ended December 31, 2013:

			Fair Value Measurements Using
	Carrying Value at December 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Non-Cash Impairment Loss
Impairment of long-lived assets disposed of other than by sale	$	--	$	--	$	--	$	--	$	79.4
Impairment of long-lived assets held and used		44.6		--		--		44.6		9.0
Impairment of long-lived assets to be disposed of by sale		0.6		--		--		0.6		9.0
Total									$	97.4

Our non-cash asset impairment charges for the year ended December 31, 2012 are a component of operating costs and expenses on our Statements of Consolidated Operations and primarily related to the abandonment of crude oil and natural gas pipeline segments in Texas and the Gulf of Mexico. The following table summarizes our non-recurring fair value measurements for the year ended December 31, 2012:

			Fair Value Measurements Using
	Carrying Value at December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Non-Cash Impairment Loss
Impairment of long-lived assets disposed of other than by sale	$	0.8	$	--	$	--	$	0.8	$	56.5
Impairment of long-lived assets held and used		2.2		--		--		2.2		2.6
Impairment of long-lived assets to be disposed of by sale		--		--		--		--		4.3
Total									$	63.4

As presented in the preceding tables, our estimated fair values were based on management's expectation of the market values for such assets based on their knowledge and experience in the industry (a Level 3 type measure involving significant unobservable inputs). In many cases, there are no active markets (Level 1) or other similar recent transactions (Level 2) to compare to. Our assumptions used in such analyses are based on the nonfinancial assets' highest and best use, which includes estimated probabilities where multiple cash flow outcomes are possible.

When probability weights are used, they are generally obtained from business management personnel having oversight responsibilities for the assets being tested. Key commercial assumptions (e.g., anticipated operating margins, throughput or processing volume growth rates, timing of cash flows, etc.) that represent Level 3 unobservable inputs and test results are reviewed and certified by members of senior management.

Other Fair Value Information

The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was $22.16 billion and $17.93 billion at December 31, 2014 and 2013, respectively. The aggregate carrying value of these debt obligations was $20.48 billion and $16.88 billion at December 31, 2014 and 2013, respectively. These values are based on quoted market prices for such debt or debt of similar terms and maturities (Level 2), our credit standing and the credit standing of our counterparties. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

Inventories

12 Months Ended

Dec. 31, 2014

Inventories [Abstract]

Property, Plant and Equipment [Abstract]

Note 7. Inventories

Our inventory amounts by product type were as follows at the dates indicated:

	December 31,
	2014		2013
NGLs	$	579.1	$	593.8
Petrochemicals and refined products		295.6		395.1
Crude oil		97.8		42.6
Natural gas		41.7		61.6
Total	$	1,014.2	$	1,093.1

In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to outright purchases from third parties for cash), these volumes are valued at market-based prices during the month in which they are acquired.

Due to fluctuating commodity prices, we recognize lower of cost or market adjustments when the carrying value of our available-for-sale inventories exceeds their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. To the extent our commodity hedging strategies address inventory-related price risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 6 for a description of our commodity hedging activities.

The following table presents our total cost of sales amounts and lower of cost or market adjustments for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Cost of sales (1)		$	40,464.1		$	40,770.2		$	36,015.5
Lower of cost or market adjustments			22.8			18.5			22.1
(1) Cost of sales is a component of "Operating costs and expenses," as presented on our Statements of Consolidated Operations. Year-to-year fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment

Note 8. Property, Plant and Equipment

The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:

	Estimated Useful Life	December 31,
	in Years	2014		2013
Plants, pipelines and facilities (1)	3-45 (6)	$	30,834.9	$	27,540.4
Underground and other storage facilities (2)	5-40 (7)		2,584.2		2,101.8
Platforms and facilities (3)	20-31		659.7		659.6
Transportation equipment (4)	3-10		154.2		138.9
Marine vessels (5)	15-30		796.4		744.8
Land			262.6		176.6
Construction in progress			2,754.7		2,655.5
Total			38,046.7		34,017.6
Less accumulated depreciation			8,165.1		7,071.0
Property, plant and equipment, net		$	29,881.6	$	26,946.6

(1) Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products 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 located in the Gulf of Mexico. (4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (7) In general, the estimated useful lives of assets within this category are: 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 Year Ended December 31,
	2014			2013			2012
Depreciation expense (1)		$	1,114.1		$	1,012.4		$	900.5
Capitalized interest (2)			77.9			133.0			116.8
(1) Depreciation expense is a component of "Costs and expenses" as presented on our Statements of Consolidated Operations. (2) Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.

In October 2014, we recorded property, plant and equipment having a fair value of approximately $1.08 billion in connection with our acquisition of a controlling interest in Oiltanking (see Note 10). Oiltanking owns marine terminals located on the Houston Ship Channel and at Beaumont, Texas. At October 1, 2014, we recorded property, plant and equipment consisting of $395.6 million of terminal and pipeline assets (a component of plants, pipelines and facilities), $407.3 million of above ground storage assets (a component of other storage facilities), $76.3 million of land and $200.9 million of construction in progress in connection with this transaction. See Note 10 for additional information regarding our acquisition of Oiltanking, including the Oiltanking Merger completed on February 13, 2015.

In March 2013, we sold the Stratton Ridge-to-Mont Belvieu segment of the Seminole Pipeline, along with a related storage cavern, for cash proceeds of $86.9 million. As a result, net income for the year ended December 31, 2013 includes a $52.5 million gain attributable to the sale of these assets. The Seminole Pipeline remains connected to our Mont Belvieu complex through a newly constructed NGL pipeline that we own.

In April 2013, we sold certain lubrication oil and specialty chemical distribution assets for cash proceeds of $35.3 million. As a result, net income for the year ended December 31, 2013 includes a $6.7 million gain from the sale of these assets.

Asset Retirement Obligations

We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. Our contractual AROs primarily result from right-of-way agreements associated with our pipeline operations and real estate leases associated with our plant sites. In addition, we record AROs in connection with governmental regulations associated with the abandonment or retirement of (i) above-ground brine storage pits, (ii) offshore Gulf of Mexico platform and pipeline assets and (iii) certain marine vessels. We also record AROs in connection with regulatory requirements associated with the renovation or demolition of certain assets containing hazardous substances such as asbestos. We typically fund our ARO obligations using cash flow from operations.

Property, plant and equipment at December 31, 2014 and 2013 includes $31.3 million and $37.4 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.

The following table presents information regarding our AROs for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
ARO liability beginning balance	$	90.2		$	105.2		$	112.0
Liabilities incurred		0.1			1.7			1.7
Liabilities settled		(2.7	)		(14.2	)		(27.8	)
Revisions in estimated cash flows		4.6			(8.6	)		13.7
Accretion expense		6.1			6.1			5.6
ARO liability ending balance	$	98.3		$	90.2		$	105.2

The following table presents our forecast of accretion expense for the periods indicated:

2015			2016			2017			2018			2019
$	6.2		$	6.4		$	6.9		$	7.5		$	7.6

Certain of our unconsolidated affiliates have AROs recorded at December 31, 2014 and 2013 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our consolidated financial statements.

Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2014

Investments in Unconsolidated Affiliates [Abstract]

Investments in Unconsolidated Affiliates

Note 9. Investments in Unconsolidated Affiliates

The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method.

	Ownership Interest at December 31,	December 31,
	2014	2014		2013
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. ("VESCO")	13.1%	$	27.7	$	27.6
K/D/S Promix, L.L.C. ("Promix")	50%		38.5		45.4
Baton Rouge Fractionators LLC ("BRF")	32.2%		18.8		19.5
Skelly-Belvieu Pipeline Company, L.L.C. ("Skelly-Belvieu")	50%		40.1		40.8
Texas Express Pipeline LLC ("Texas Express")	35%		349.3		339.9
Texas Express Gathering LLC ("TEG")	45%		37.9		37.8
Front Range Pipeline LLC ("Front Range")	33.3%		170.0		134.5
Onshore Natural Gas Pipelines & Services:
White River Hub, LLC ("White River Hub")	50%		23.2		24.2
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company LLC ("Seaway")	50%		1,431.2		940.7
Eagle Ford Pipeline LLC ("Eagle Ford Crude Oil Pipeline")	50%		336.5		224.5
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. ("Poseidon")	36%		31.8		41.7
Cameron Highway Oil Pipeline Company ("Cameron Highway")	50%		201.3		207.7
Deepwater Gateway, L.L.C. ("Deepwater Gateway")	50%		79.6		84.5
Neptune Pipeline Company, L.L.C. ("Neptune")	25.7%		34.9		38.7
Southeast Keathley Canyon Pipeline Company L.L.C. ("SEKCO")	50%		146.1		159.2
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC ("BRPC")	30%		6.5		7.6
Centennial Pipeline LLC ("Centennial")	50%		66.1		60.1
Other	Various		2.5		2.7
Total		$	3,042.0	$	2,437.1

NGL Pipelines & Services

The principal business activity of each investee included in our NGL Pipelines & Services segment is described as follows:

§	VESCO owns a natural gas processing facility in south Louisiana and a related gathering system that gathers natural gas from certain offshore developments for delivery to its natural gas processing facility.

Promix owns an NGL fractionation facility and related storage caverns located in south Louisiana. The facility receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast. In addition, Promix owns an NGL gathering system that gathers mixed NGLs from processing plants in southern Louisiana for its fractionator.

§	BRF owns an NGL fractionation facility located in south Louisiana that receives mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana.

§	Skelly-Belvieu owns a pipeline that transports mixed NGLs from Skellytown, Texas to Mont Belvieu, Texas. The Skelly-Belvieu Pipeline receives NGLs through a pipeline interconnect with our Mid-America Pipeline System in Skellytown, Texas.

Texas Express owns an NGL pipeline that extends from Skellytown, Texas to our NGL fractionation and storage complex at Mont Belvieu, Texas. This pipeline commenced operations in November 2013. Mixed NGL volumes from the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the pipeline via an interconnect with our Mid-America Pipeline System near Skellytown. The pipeline also transports mixed NGL volumes from two gathering systems owned by TEG to Mont Belvieu. In addition, mixed NGL volumes from the Denver-Julesburg supply basin are transported to the pipeline using the Front Range pipeline, which commenced operations in February 2014.

TEG owns two NGL gathering systems that deliver volumes to the Texas Express Pipeline. These gathering systems commenced operations in November 2013. The Elk City gathering system currently gathers mixed NGLs from natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma. The North Texas gathering system currently gathers mixed NGLs from natural gas processing plants in the Barnett Shale production area in North Texas. Enbridge serves as operator of these two NGL gathering systems.

Front Range owns an NGL pipeline that transports mixed NGLs from natural gas processing plants located in the Denver-Julesburg Basin in Colorado to an interconnect with our Texas Express pipeline and Mid-America Pipeline System at Skellytown, Texas. The Front Range pipeline commenced operations in February 2014.

Onshore Natural Gas Pipelines & Services

White River Hub owns a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado. The facility enables producers to access six interstate natural gas pipelines.

Onshore Crude Oil Pipelines & Services

The principal business activity of each investee included in our Onshore Crude Oil Pipelines & Services segment is described as follows:

Seaway owns a pipeline that connects the Cushing, Oklahoma hub with markets in Southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System. The Cushing hub is a major industry trading hub and price settlement point for West Texas Intermediate on the New York Mercantile Exchange.

The Longhaul System provides north-to-south transportation of crude oil from the Cushing hub to Seaway's Jones Creek terminal near Freeport, Texas and our terminal located near Katy, Texas. In early 2012, Seaway undertook a reversal of the flow of its Longhaul System and began providing north-to-south transportation service in May 2012. Previously, this pipeline was used to transport crude oil in the opposite direction from the Jones Creek terminal to the Cushing hub.

In June 2014 we completed a pipeline looping project involving our Longhaul System. This expansion project entailed the construction of an additional pipeline that transports crude oil southbound from the Cushing hub to Seaway's Jones Creek terminal.

The Freeport System consists of a ship unloading dock, three pipelines and other related facilities that transport crude oil from Freeport, Texas to the Jones Creek terminal. The Texas City System consists of a ship unloading dock, storage tanks, various pipelines and other related facilities that deliver crude oil from Texas City, Texas to Galena Park, Texas and other nearby locations. The Freeport System and Texas City System make only intrastate movements. Seaway also owns storage tanks at the Jones Creek terminal, which are connected to the Longhaul System.

Eagle Ford Pipeline LLC owns a crude oil pipeline that transports crude oil and condensate for producers in South Texas. The system consists of a crude oil and condensate pipeline extending from Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and continuing on to Corpus Christi, Texas. The system also includes a pipeline segment extending from Three Rivers to an interconnect with our South Texas Crude Oil Pipeline System in Wilson County. This system, which commenced operations in July 2013, includes a marine terminal facility at Corpus Christi and storage capacity across the system. Plains All American Pipeline, L.P. ("Plains"), our joint venture partner in the pipeline, serves as operator of the system.

Offshore Pipelines & Services

The principal business activity of each investee included in our Offshore Pipelines & Services segment is described as follows:

§	Poseidon owns a crude oil pipeline that transports crude oil production from the outer continental shelf and deepwater areas of the Gulf of Mexico offshore Louisiana to onshore facilities in south Louisiana.

§	Cameron Highway owns a crude oil pipeline that transports crude oil production from deepwater areas of the Gulf of Mexico, primarily the Green Canyon area, for delivery to refineries and terminals in southeast Texas.

§	Deepwater Gateway owns an offshore platform that processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of Mexico.

Neptune owns the Manta Ray Offshore Gathering System and Nautilus System, both of which are natural gas pipeline systems located in the Gulf of Mexico. As a result of declining pipeline throughput volumes forecast for these systems in 2014 and future years, we recorded a $4.8 million non-cash impairment charge related to our equity investment in Neptune in 2013.

§	SEKCO, upon construction, will own a crude oil gathering pipeline serving the Lucius oil and gas field located in the southern Keathley Canyon area of the deepwater central Gulf of Mexico. The SEKCO Oil Pipeline commenced operations in July 2014.

Petrochemical & Refined Products Services

The principal business activity of each significant investee included in our Petrochemical & Refined Products Services segment is described as follows:

§	BRPC owns a propylene fractionation facility located in south Louisiana that fractionates refinery grade propylene into chemical grade propylene.

§	Centennial owns an interstate refined products pipeline that extends from an origination facility in Beaumont, Texas, to Bourbon, Illinois. Centennial also owns a refined products storage terminal located near Creal Springs, Illinois.

Other Investments

Liquidation of Investment in Energy Transfer Equity

The Other Investments segment included our noncontrolling ownership interest in Energy Transfer Equity, which was accounted for using the equity method until January 18, 2012. Since our ownership interest in Energy Transfer Equity exceeded 3% of its total ownership interests through January 18, 2012, we accounted for our investment in Energy Transfer Equity using the equity method. On January 18, 2012, we sold 22,762,636 of these common units in a private transaction, which generated cash proceeds of $825.1 million. As a result of this transaction, our ownership interest in Energy Transfer Equity was reduced below 3%, and we discontinued using the equity method to account for this investment and began accounting for it as an investment in available-for-sale equity securities. The remaining 6,540,878 units were sold systematically through April 27, 2012 and generated additional total cash proceeds of $270.2 million. In the aggregate, the liquidation of this investment during 2012 resulted in $68.8 million of gains that are a component of "Other income" on our Statements of Consolidated Operations.

All activities included in the Other Investments business segment ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our investment in Energy Transfer Equity. See Note 14 for information regarding our business segments.

Equity Earnings and Excess Cost

The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
NGL Pipelines & Services	$	30.6		$	15.7		$	15.9
Onshore Natural Gas Pipelines & Services		3.6			3.8			4.4
Onshore Crude Oil Pipelines & Services		184.6			140.3			32.6
Offshore Pipelines & Services		54.0			29.8			26.9
Petrochemical & Refined Products Services (1)		(13.3	)		(22.3	)		(17.9	)
Other Investments (2)		--			--			2.4
Total	$	259.5		$	167.3		$	64.3

(1) Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value. (2) With respect to the year ended December 31, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.

On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying carrying value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in Promix, Skelly-Belvieu, Seaway, Poseidon, Cameron Highway, Centennial and La Porte at December 31, 2014. These excess cost amounts are attributable to the fair value of the underlying tangible assets of these entities exceeding their respective book carrying values at the time of our acquisition of ownership interests in these entities. We amortize such excess cost amounts as a reduction to equity earnings in a manner similar to depreciation.

The following table presents our unamortized excess cost amounts by business segment at the dates indicated:

	December 31,
	2014		2013
NGL Pipelines & Services	$	26.5	$	27.7
Onshore Crude Oil Pipelines & Services		21.7		17.8
Offshore Pipelines & Services		9.0		10.0
Petrochemical & Refined Products Services		2.4		2.6
Total	$	59.6	$	58.1

The following table presents our amortization of excess cost amounts by business segment for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
NGL Pipelines & Services	$	1.2	$	1.2	$	1.0
Onshore Crude Oil Pipelines & Services		0.9		0.7		0.7
Offshore Pipelines & Services		1.0		1.3		1.2
Petrochemical & Refined Products Services		0.2		0.1		0.2
Other Investments (1)		--		--		0.3
Total	$	3.3	$	3.3	$	3.4

(1) Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity through January 18, 2012, which is the date we ceased using the equity method to account for this investment.

The following table presents forecasted amortization of excess cost amounts for the years indicated.

2015			2016			2017			2018			2019
$	3.3		$	3.3		$	3.3		$	3.3		$	3.3

Other

The credit agreements of Poseidon and Centennial restrict their ability to pay cash dividends if a default or event of default (as defined in each credit agreement) has occurred and is continuing at the time such payments are scheduled to be paid. These businesses were in compliance with the terms of their credit agreements at December 31, 2014.

Acquisition of Oiltanking Partners, L.P.

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Business Combinations

Note 10. Acquisition of Oiltanking Partners, L.P.

Step 1 of the Oiltanking acquisition. On October 1, 2014, we acquired Oiltanking GP and the related incentive distribution rights, 15,899,802 common units and 38,899,802 subordinated units of Oiltanking from OTA. We paid total consideration of approximately $4.4 billion to OTA comprised of $2.21 billion in cash and 54,807,352 Enterprise common units for these ownership interests and rights. We also paid $228.3 million to assume the outstanding loans, including related accrued interest, owed by Oiltanking or its subsidiaries to OTA. Collectively, these transactions are referred to as "Step 1" of the Oiltanking acquisition. We funded the cash consideration for the Step 1 transactions using borrowings under our new $1.5 Billion 364-Day Credit Agreement (see Note 12), proceeds from the sale of short-term notes under our commercial paper program and cash on hand. As a result of our acquisition of Oiltanking GP, we began consolidating the financial statements of Oiltanking and its general partner on October 1, 2014.

Oiltanking owns marine terminals located on the Houston Ship Channel and at the Port of Beaumont with a total of 12 ship and barge docks and approximately 26 MMBbls of crude oil and petroleum products storage capacity. Oiltanking's marine terminal on the Houston Ship Channel is connected by pipeline to our Mont Belvieu, Texas complex and is integral to our growing LPG export, crude oil storage and octane enhancement and propylene businesses. Our Enterprise Crude Houston, or ECHO, facility is also connected to Oiltanking's system. We have had a strategic relationship and enjoyed mutual growth with Oiltanking and its predecessors since 1983. The combination of our legacy midstream assets and Oiltanking's access to waterborne markets and crude oil and petroleum products storage assets extends and broadens our midstream energy services business. We believe this combination benefits our producing and consuming customers by enhancing their respective access to supplies, domestic and international markets, and storage.

In accordance with Accounting Standards Codification ("ASC") Topic 805, Business Combinations, we account for acquisitions by applying the acquisition method of accounting. The acquisition method of accounting requires, among other things, that the assets acquired and liabilities assumed in a business combination be measured at their fair values as of the closing date of the acquisition. We engaged an independent third party business valuation expert to assist us in estimating the fair values of the tangible and intangible assets of Oiltanking. With the exception of the fair value assigned to the Liquidity Option Agreement (see Note 18), our purchase price allocation is final. We expect to finalize the fair value of the Liquidity Option Agreement as soon as practicable but no later than one year from the acquisition date.

The following table summarizes the consideration paid in Step 1 of the Oiltanking acquisition and the amounts of the assets acquired and liabilities assumed at the acquisition date, as well as the fair value of the noncontrolling interest in Oiltanking at October 1, 2014.

Consideration:
Cash	$	2,438.3
Equity instruments (54,807,352 common units of Enterprise) (1)		2,171.5
Fair value of total consideration transferred in Step 1	$	4,609.8

Identifiable assets acquired in business combination:
Current assets, including cash of $21.5 million	$	68.0
Property, plant and equipment		1,080.1
Identifiable intangible assets:
Customer relationship intangible assets (2)		1,192.4
Contract-based intangible assets (2)		297.5
IDRs		1,459.2
Total identifiable intangible assets		2,949.1
Other assets		227.6
Total assets acquired		4,324.8
Liabilities assumed in business combination:
Current liabilities		(84.8	)
Long-term debt		(223.3	)
Other long-term liabilities (3)		(129.7	)
Total liabilities assumed		(437.8	)
Noncontrolling interest in Oiltanking (4)		(1,397.2	)
Total assets acquired less liabilities assumed and noncontrolling interest		2,489.8
Total consideration given for ownership interests in Oiltanking in Step 1		4,609.8
Goodwill	$	2,120.0

(1) The fair value of the equity-based consideration paid in connection with Step 1 of the Oiltanking acquisition was based on the closing market price of Enterprise's common units of $39.62 per unit on the acquisition date. (2) The weighted-average amortization period for the customer relationship intangible assets is 29 years and for the contract-based intangible assets is six years. (3) Other long-term liabilities includes $119.4 million for the Liquidity Option Agreement. The fair value assigned to the Liquidity Option Agreement is provisional pending completion of certain tax-related computations. See Note 18 for information regarding this agreement. (4) From an accounting perspective, Enterprise acquired control of Oiltanking as a result of completing Step 1. In accordance with ASC 805, Business Combinations, the estimated fair value of Oiltanking's common units held by parties other than Enterprise following Step 1 (i.e., the "noncontrolling interest") is based on 28,328,890 common units held by third parties on October 1, 2014 multiplied by the closing unit price for Oiltanking common units on that date of $49.32 per unit.

As noted previously, we paid $228.3 million to acquire the outstanding loans, including related accrued interest of $2.5 million, owed by Oiltanking or its subsidiaries to OTA. Of the $228.3 million in notes and interest receivable, $5.0 million is classified as a current asset and $223.3 million as a long-term other asset in the preceding table. The notes and interest receivables from Oiltanking, along with the corresponding notes and interest payables by Oiltanking, are eliminated in the preparation of our consolidated financial statements.

We estimated the fair value of the acquired property, plant and equipment using a combination of the cost, market and income approaches, depending on the component. The fair value of property, plant and equipment consisted of real property of $95.4 million and personal property of $984.7 million. For additional information regarding our property, plant and equipment, see Note 8.

The fair values of the identifiable intangible assets were estimated using the income approach, specifically, a discounted cash flow analysis. The discounted cash flow analysis consisted of discounting to present value the cash flow projections for the identifiable intangible assets using discount rates ranging from 5.5% to 8.5%. The cash flow projections for the identifiable intangible assets were based on cash flow estimates used to price the Oiltanking acquisition, and the discount rates were based on a benchmarking analysis with reference to the implied rate of return on the Oiltanking acquisition and to a market participant weighted average cost of capital.

The customer relationship intangible assets represent the continued expected patronage of Oiltanking's third party storage and terminal customers, and includes our expectation of future storage, throughput and other terminaling services from these customers. We valued the customer relationships using the multi-period excess earnings method under the income approach. This valuation method is based on forecasting revenue for the existing customer base and then adjusting for expected customer attrition rates. The operating cash flows are then reduced by contributory asset charges.

The contract-based intangible assets represent specific commercial rights we acquired in connection with third party customer firm contracts for storage capacity at the Houston and Beaumont facilities. We valued the contracts using the multi-period excess earnings method under the income approach. This valuation method is based on future contractual revenues less those costs necessary to fulfill the contracts, including contributory asset charges. If a contract was in its renewal period and had not been cancelled, we assumed the contract was renewed on equivalent terms to the prior contract. We only valued those contracts that specified a minimum monthly fee, excluding contracts with a de minimis fee.

The IDRs of Oiltanking are held by its general partner. The IDRs allow the holder to participate in increasing levels of cash distributions after a minimum quarterly distribution exceeds specified target levels. To value the IDRs, we relied on the discounted cash flow method under the income approach. A discount rate of approximately 8.5% was applied to the projected cash flows. With respect to Oiltanking, its IDRs provide that if cash distributions to unitholders exceed approximately $0.1940625 per unit, cash distributions to unitholders and the general partner would be paid according to the following allocations:

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit Target Amount	Unitholders	General Partner
Minimum quarterly distribution	$0.16875	98%	2%
First target distribution	above $0.16875 up to $0.1940625	98%	2%
Second target distribution	above $0.1940625 up to $0.2109375	85%	15%
Third target distribution	above $0.2109375 up to $0.253125	75%	25%
Thereafter	above $0.253125	50%	50%

At the acquisition date, Oiltanking's most recent paid quarterly cash distribution was $0.26 per unit, which placed the IDRs in the highest tier at 50% of cash distributions in excess of $0.253125 per unit. In February 2015, Oiltanking paid a quarterly cash distribution of $0.285 per unit with respect to the fourth quarter of 2014.

The excess of the purchase price over the estimated fair values of the acquired tangible net assets and identifiable intangible assets was recorded as goodwill. The factors contributing to the recognition of goodwill are based on a variety of strategic and synergistic benefits that are expected to be realized from the Oiltanking acquisition. These benefits include (i) opportunities for new business and repurposing existing assets for "best use" in order to meet anticipated increased demand for export and logistical services for petroleum products related to North American crude oil, condensate and NGL production, (ii) securing ownership and control of assets that are essential to our other midstream assets and (iii) cost savings from integrating Oiltanking into our business system.

For additional information regarding our intangible assets and goodwill amounts, see Note 11.

Although we are not subject to federal income tax, our partners are individually responsible for paying federal income taxes on their share of our taxable income. In deriving our taxable income, the amount assigned to goodwill in this transaction will be amortized over a period of 15 years.

Our consolidated revenues and net income included $57.5 million and $8.1 million, respectively, from Oiltanking for the three months ended December 31, 2014.

We incurred $3.8 million of direct transaction costs in connection with Step 1 of the Oiltanking acquisition in the year ended December 31, 2014. These costs are included in general and administrative costs in the accompanying Statements of Consolidated Operations.

Since the effective date of Step 1 of the Oiltanking acquisition was October 1, 2014, our Statements of Consolidated Operations do not include earnings from these businesses prior to this date. The following table presents selected unaudited pro forma earnings information for the years ended December 31, 2014 and 2013 as if the acquisition had been completed on January 1, 2013. This pro forma information was prepared using historical financial data for Oiltanking and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been for the years ended December 31, 2014 and 2013 had we acquired Oiltanking on January 1, 2013.

	For Year Ended December 31,
	2014		2013
Pro forma earnings data:
Revenues	$	48,087.5	$	47,875.7
Costs and expenses		44,509.0		44,522.3
Operating income		3,838.0		3,520.7
Net income		2,877.5		2,632.8
Net income attributable to noncontrolling interest		75.0		39.5
Net income attributable to limited partners		2,802.5		2,593.3

Basic earnings per unit:
As reported basic units outstanding		1,848.7		1,788.0
Pro forma basic units outstanding		1,903.5		1,842.8
As reported basic earnings per unit	$	1.51	$	1.45
Pro forma basic earnings per unit	$	1.47	$	1.41
Diluted earnings per unit:
As reported diluted units outstanding		1,895.2		1,842.6
Pro forma diluted units outstanding		1,950.0		1,897.4
As reported diluted earnings per unit	$	1.47	$	1.41
Pro forma diluted earnings per unit	$	1.44	$	1.37

The foregoing supplemental pro forma earnings data for the year ended December 31, 2014 were adjusted to exclude $3.8 million of acquisition-related direct costs incurred in 2014. Pro forma earnings data for the year ended December 31, 2013 was adjusted to include these charges.

Automatic conversion of subordinated units. Following Step 1 of the Oiltanking acquisition, but not part of Step 2 of the acquisition, on November 17, 2014, the 38,899,802 Oiltanking subordinated units held by Enterprise automatically converted into an equal number of Oiltanking common units pursuant to the terms of the Oiltanking partnership agreement. Following this conversion, Enterprise owned 54,799,604 Oiltanking common units, or approximately 65.9% of its outstanding common units.

Step 2 of the Oiltanking acquisition. As a second step of the Oiltanking acquisition (separately negotiated by the conflicts committee of Oiltanking's general partner on behalf of Oiltanking), we entered into an Agreement and Plan of Merger (the "merger agreement") with Oiltanking on November 11, 2014 that provided for the following:

§	the merger of a wholly owned subsidiary of Enterprise with and into Oiltanking, with Oiltanking surviving the merger as a wholly owned subsidiary of Enterprise (the "Oiltanking Merger"); and

all outstanding common units of Oiltanking at the effective time of the merger held by Oiltanking's public unitholders (which consist of Oiltanking unitholders other than Enterprise and its subsidiaries) to be cancelled and converted into Enterprise common units based on an exchange ratio of 1.30 Enterprise common units for each Oiltanking common unit.

In accordance with the merger agreement and Oiltanking's partnership agreement, the merger was submitted to a vote of Oiltanking's common unitholders, with the required majority of unitholders (including Enterprise's ownership interests representing approximately 65.9% of Oiltanking's outstanding common units) voting to approve the merger on February 13, 2015. Upon approval of the merger, a total of 36,827,557 Enterprise common units were issued to Oiltanking's former public unitholders.

From an accounting perspective, completion of Step 2 of the Oiltanking acquisition will have the following significant impacts on our consolidated financial statements in the first quarter of 2015:

The merger will be accounted for in accordance with ASC Topic 810, Consolidations – Overall – Changes in Parent's Ownership Interest in a Subsidiary. As a result, changes in our ownership interest in Oiltanking, while we retain a controlling financial interest in Oiltanking through our ownership of its general partner and a majority of its common units, will be accounted for as an equity transaction with no gain or loss recognized as a result of the merger. The merger represents our acquisition of the noncontrolling interests in Oiltanking; therefore, noncontrolling interests attributable to Oiltanking as presented on the Consolidated Balance Sheet at the merger date will be extinguished, with a corresponding increase in our partners' equity to reflect the February 2015 issuance of 36,827,557 new common units.

Upon completion of the merger, the IDRs of Oiltanking will be cancelled since we now own 100% of the future cash flows attributable to the Oiltanking businesses. As a result, the $1.46 billion carrying value of the IDR intangible asset was reclassified to goodwill and allocated among our business segments (see Note 11).

FTC Matters. On February 23, 2015, we received a Civil Investigative Demand and a related Subpoena Duces Tecum from the Federal Trade Commission requesting specified information relating to the Oiltanking acquisition. We are in the process of complying with the requests and are cooperating with the investigation. Based on the limited information that Enterprise has at this time, we are unable to predict the outcome of the investigation.

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

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Intangible Assets and Goodwill [Abstract]

Intangible Assets and Goodwill

12 Months Ended

Dec. 31, 2014

Intangible Assets and Goodwill

Note 11. Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by business segment at the dates indicated:

	December 31, 2014							December 31, 2013
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	340.8	$	(183.2	)	$	157.6	$	340.8	$	(165.7	)	$	175.1
Contract-based intangibles		277.7		(178.7	)		99.0		281.3		(171.2	)		110.1
Incentive distribution rights		432.6		--			432.6		--		--			--
Segment total		1,051.1		(361.9	)		689.2		622.1		(336.9	)		285.2
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles		1,163.6		(308.9	)		854.7		1,163.6		(281.2	)		882.4
Contract-based intangibles		466.0		(347.8	)		118.2		466.1		(330.7	)		135.4
Segment total		1,629.6		(656.7	)		972.9		1,629.7		(611.9	)		1,017.8
Onshore Crude Oil Pipelines & Services:
Customer relationship intangibles		1,108.0		(7.7	)		1,100.3		10.7		(6.3	)		4.4
Contract-based intangibles		281.4		(13.5	)		267.9		0.4		(0.3	)		0.1
Incentive distribution rights		855.4		--			855.4		--		--			--
Segment total		2,244.8		(21.2	)		2,223.6		11.1		(6.6	)		4.5
Offshore Pipelines & Services:
Customer relationship intangibles		195.8		(154.9	)		40.9		203.9		(150.0	)		53.9
Contract-based intangibles		1.2		(0.5	)		0.7		1.2		(0.4	)		0.8
Segment total		197.0		(155.4	)		41.6		205.1		(150.4	)		54.7
Petrochemical & Refined Products Services:
Customer relationship intangibles		198.4		(43.3	)		155.1		104.3		(38.2	)		66.1
Contract-based intangibles		56.3		(7.8	)		48.5		39.9		(6.0	)		33.9
Incentive distribution rights		171.2		--			171.2		--		--			--
Segment total		425.9		(51.1	)		374.8		144.2		(44.2	)		100.0
Total all segments	$	5,548.4	$	(1,246.3	)	$	4,302.1	$	2,612.2	$	(1,150.0	)	$	1,462.2

The following table presents the amortization expense of our intangible assets by business segment for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
NGL Pipelines & Services	$	33.1	$	36.4	$	39.7
Onshore Natural Gas Pipelines & Services		45.0		50.1		63.4
Onshore Crude Oil Pipelines & Services		15.7		1.4		0.9
Offshore Pipelines & Services		9.9		11.5		11.3
Petrochemical & Refined Products Services		6.9		6.2		10.4
Total	$	110.6	$	105.6	$	125.7

The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated:

2015			2016			2017			2018			2019
$	150.5		$	152.3		$	149.3		$	142.7		$	131.3

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 the ability to provide services to them and (ii) the customers now have the ability to make direct contact with us. Customer relationships may arise from contractual arrangements (such as service contracts) and through means other than contracts, such as through regular contact by sales or service representatives.

At December 31, 2014, the carrying value of our portfolio of customer relationship intangible assets was $2.31 billion. The following information summarizes the significant components of this category of intangible assets:

§	Oiltanking customer relationships – We recorded customer relationship intangible assets in connection with the Oiltanking acquisition in October 2014 (see Note 10). The carrying values of these intangible assets at December 31, 2014 are presented in the following table:

	Gross Value		Accumulated Amortization			Carrying Value
Onshore Crude Oil Pipelines & Services:
Oiltanking customer relationships	$	1,098.4	$	(1.4	)	$	1,097.0
Petrochemical & Refined Products Services:
Oiltanking customer relationships		94.1		--			94.1
Total	$	1,192.5	$	(1.4	)	$	1,191.1

The economic value we attributed to these customer relationships was estimated using recognized business valuation techniques based on several key assumptions, which include assumptions regarding the continued expected patronage of storage and terminal customers, and our expectation of future storage, throughput and other terminaling services from these customers.

These intangible assets are being amortized to earnings over their estimated economic life of 29 years through 2043. Amortization expense attributable to these customer relationships is recorded using a method that closely resembles the pattern in which the economic benefits are expected to be consumed or otherwise used.

State Line and Fairplay customer relationships – We acquired these customer relationships in connection with our acquisition of the State Line and Fairplay natural gas gathering systems in May 2010. The carrying values of these intangible assets at December 31, 2014 are presented in the following table:

	Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Fairplay natural gas processing customer relationships	$	103.4	$	(27.2	)	$	76.2
Onshore Natural Gas Pipelines & Services:
State Line natural gas gathering customer relationships		675.0		(68.7	)		606.3
Fairplay natural gas gathering customer relationships		116.6		(30.7	)		85.9
Total	$	895.0	$	(126.6	)	$	768.4

In this context, a customer relationship is broadly defined as a relationship between the natural gas gathering system and the production fields from which it gathers natural gas. Ownership of the gathering system creates a level of access to producers in a field analogous to having a franchise over a particular area. Efficient operation of the gathering system helps to support commercial relationships with existing producers and provides us with opportunities to establish relationships with new ones. The duration of such customer relationships are limited by the estimated economic life of the underlying resource basins.

Customer relationship intangibles related to the State Line system have an estimated economic life of 37 years through 2047. The natural gas gathering and processing customer relationships associated with the Fairplay system have an estimated economic life of 23 years through 2033. Amortization expense attributable to these customer relationships is recorded using the units-of-production method based on gathering volumes. This method of amortization allows for expense to be recorded in a manner that closely resembles the pattern in which we benefit from natural gas gathering and processing services provided to customers.

San Juan Gathering System customer relationships – We acquired these customer relationships in connection with a merger transaction completed in September 2004. At December 31, 2014, the carrying value of this group of intangible assets was $146.9 million. These intangible assets are being amortized to earnings over their estimated economic life of 35 years through 2039. Amortization expense attributable to these customer relationships is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying natural gas resource basins are expected to be consumed or otherwise used.

Offshore Pipeline & Platform customer relationships – We acquired these customer relationships in connection with a merger transaction completed in September 2004. At December 31, 2014, the carrying value of this group of intangible assets was $40.9 million. These intangible assets are being amortized to earnings over their estimated economic lives, which range from 11 to 33 years (i.e., through 2015 to 2037). Amortization expense attributable to these customer relationships is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying crude oil and natural gas resource basins are expected to be consumed or otherwise used.



Encinal natural gas processing customer relationships – We acquired these customer relationships in connection with our acquisition of certain South Texas assets in 2006. At December 31, 2014, the carrying value of this group of intangible assets was $50.2 million. These intangible assets are being amortized to earnings over their estimated economic life of 20 years through 2026. Amortization expense attributable to these customer relationships is recorded using a method that closely resembles the pattern in which the economic benefit of the underlying natural gas resource basins are expected to be consumed or otherwise used.

Contract-based intangible assets. Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations or asset purchases. At December 31, 2014, the carrying value of our contract-based intangible assets was $534.3 million. The following information summarizes the significant components of this category of intangible assets:

§	Oiltanking customer contracts – We recorded customer contract intangible assets in connection with the Oiltanking acquisition in October 2014 (see Note 10). The carrying values of these intangible assets at December 31, 2014 are presented in the following table:

	Gross Value		Accumulated Amortization			Carrying Value
Onshore Crude Oil Pipelines & Services:
Oiltanking customer contracts	$	281.0	$	(13.2	)	$	267.8
Petrochemical & Refined Products Services:
Oiltanking customer contracts		16.4		(0.7	)		15.7
Total	$	297.4	$	(13.9	)	$	283.5

The economic value we attributed to these customer contracts was estimated using recognized business valuation techniques based on several key assumptions, which include the contractual life of the contracts and expected renewal periods.

These intangible assets are being amortized to earnings over their estimated weighted-average economic lives of six years. Amortization expense attributable to these customer relationships is recorded using a method that closely resembles the pattern in which the economic benefits are expected to be consumed or otherwise used.

Jonah natural gas gathering agreements – These intangible assets represent the value attributed to certain natural gas gathering contracts on the Jonah Gathering System that were acquired by TEPPCO in 2001. At December 31, 2014, the carrying value of this group of intangible assets was $82.8 million. These intangible assets are being amortized to earnings over their estimated economic life of 40 years through 2041. Amortization expense attributable to these intangible assets is recorded using a units-of-production method based on gathering volumes.

Shell Processing Agreement – This margin-band/keepwhole natural gas processing agreement grants us the right to process Shell Oil Company's (or its assignee's) current and future natural gas production from the state and federal waters of the Gulf of Mexico. We acquired the Shell Processing Agreement in connection with our purchase of certain U.S. Gulf Coast midstream energy assets from Shell Oil Company in 1999. At December 31, 2014, the carrying value of this intangible asset was $50.6 million. This intangible asset is being amortized to earnings on a straight-line basis over its estimated economic life of 20 years through 2019.

San Juan basin natural gas gathering agreements – These intangible assets represent the value attributed to certain natural gas gathering contracts with producers in the San Juan basin that were acquired by TEPPCO in 2002. At December 31, 2014, the carrying value of these intangible assets was $34.6 million. These intangible assets are being amortized to earnings over their estimated economic life of 20 years through 2021. Amortization expense attributable to these intangible assets is recorded using a units-of-production method based on gathering volumes.

Incentive distribution rights. We recorded an indefinite-lived intangible asset valued at an aggregate $1.46 billion in connection with our acquisition of the Oiltanking IDRs in October 2014. The IDRs represented contractual rights to future incentive cash distributions to be paid by Oiltanking. Such rights were granted to Oiltanking GP by Oiltanking under the terms of Oiltanking's partnership agreement. In accordance with Oiltanking's partnership agreement, Oiltanking GP could separate and sell the IDRs independent of its other residual general partner interest in Oiltanking. For the period in which the IDRs were outstanding (see below), we considered these rights to be an indefinite-lived intangible asset. Our determination of an indefinite life was based on our expectation that Oiltanking would continue to pay incentive distributions under the terms of its partnership agreement for an indefinite period.

To the extent outstanding at each balance sheet date, indefinite-lived intangible assets are tested for impairment annually, or more frequently if circumstances indicate that it is more likely than not that the fair value of the asset is less than its carrying value. We tested the Oiltanking IDRs for impairment at December 31, 2014. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of the IDRs was reclassified to goodwill (see Note 10).

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; however, it is subject to annual impairment testing at the end of each fiscal year, and more frequently, if circumstances indicate it is probable that the fair value of goodwill is below its carrying amount. The following table presents changes in the carrying amount of goodwill during the periods indicated:

	NGL Pipelines & Services		Onshore Natural Gas Pipelines & Services		Onshore Crude Oil Pipelines & Services			Offshore Pipelines & Services			Petrochemical & Refined Products Services			Consolidated Total
Balance at December 31, 2011	$	341.2	$	296.3	$	311.2		$	82.1		$	1,061.5		$	2,092.3
Reclassification to assets held for sale		--		--		--			--			(5.5	)		(5.5	)
Balance at December 31, 2012		341.2		296.3		311.2			82.1			1,056.0			2,086.8
Goodwill related to the sale of assets		--		--		(6.1	)		--			(0.7	)		(6.8	)
Balance at December 31, 2013		341.2		296.3		305.1			82.1			1,055.3			2,080.0
Reclassification of goodwill		520.0		--		--			--			(520.0	)		--
Goodwill related to the sale of assets		--		--		--			(0.1	)		--			(0.1	)
Goodwill related to Oiltanking acquisition		1,319.2		--		554.8			--			246.0			2,120.0
Balance at December 31, 2014	$	2,180.4	$	296.3	$	859.9		$	82.0		$	781.3		$	4,199.9

Goodwill impairment testing involves determining the estimated fair value of the associated reporting unit. Our fair value estimates are based on assumptions regarding the future economic prospects of the businesses that comprise the reporting unit. Such assumptions include: (i) discrete financial forecasts for the businesses contained within the reporting unit, which, in turn, rely on management's estimates of operating margins, throughput volumes and similar factors; (ii) long-term growth rates for cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. When management's assumptions are used to estimate reporting unit fair value, we believe such assumptions are consistent with the assumptions market participants would make to estimate the reporting unit's fair value. Based on our most recent goodwill impairment test at December 31, 2014, each reporting unit's fair value was substantially in excess of its carrying value (i.e., by at least 10%).

In January 2014, our ATEX pipeline commenced operations. In addition to the construction of new assets, this project involved repurposing portions of the TE Products Pipeline to accommodate the southbound delivery of ethane produced from the Marcellus and Utica Shales to the U.S. Gulf Coast. The repurposed assets were reclassified from the Petrochemical & Refined Products Services business segment to the NGL Pipelines & Services business segment in January 2014 when ATEX commenced operations. Pipeline assets that continue to be utilized by the TE Products Pipeline in the northbound delivery of refined products and other hydrocarbons from the U.S. Gulf Coast remain in the Petrochemical & Refined Products Services business segment.

In total, the carrying value of the fixed assets at January 1, 2014 that were transferred from the TE Products Pipeline to ATEX was $73.7 million. Based on the relative fair values of the assets involved, we also transferred $520.0 million of goodwill from the Petrochemical & Refined Products Services business segment to the NGL Pipelines & Services business segment. The relative fair values of the segment assets were determined based on assumptions regarding the future economic prospects of ATEX versus the other assets that would remain in the associated reporting unit. These assumptions included: (i) discrete financial forecasts for the pipelines and related businesses contained within the reporting unit, which, in turn, relied on management's estimates of future operating margins, throughput volumes and similar factors; (ii) long-term growth rates for cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. We believe our assumptions are consistent with those that market participants would utilize in estimating the reporting unit's fair value.

In October 2014, we recorded $2.12 billion of goodwill in connection with Step 1 of our acquisition of Oiltanking. In general, we attribute this goodwill to our ability to leverage the acquired business with our existing asset base to create future business opportunities. In February 2015, $1.46 billion of Oiltanking IDRs originally recorded as intangible assets were cancelled and the carrying value of the IDRs was reclassified to goodwill. See Note 10 for a discussion of goodwill attributable to Step 1 of the Oiltanking acquisition and related changes in our goodwill balances in connection with completing the Oiltanking Merger in February 2015.

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

Debt Obligations

12 Months Ended

Dec. 31, 2014

Debt Obligations [Abstract]

Debt Obligations

Note 12. Debt Obligations

The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:

	December 31,
	2014			2013
EPO senior debt obligations:
Commercial Paper Notes, variable-rate (1)	$	906.5		$	475.0
Senior Notes O, 9.75% fixed-rate, due January 2014		--			500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		--			650.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0			250.0
Senior Notes X, 3.70% fixed-rate, due June 2015		400.0			400.0
Senior Notes FF, 1.25% fixed-rate, due August 2015		650.0			650.0
$1.5 Billion 364-Day Credit Agreement, variable-rate, due September 2015		--			--
Senior Notes AA, 3.20% fixed-rate, due February 2016		750.0			750.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0			800.0
Senior Notes V, 6.65% fixed-rate, due April 2018		349.7			349.7
$3.5 Billion Multi-Year Revolving Credit Facility, variable-rate, due June 2018		--			--
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
Senior Notes LL,2.55% fixed-rate, due October 2019		800.0			--
Senior Notes Q, 5.25% fixed-rate, due January 2020		500.0			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Senior Notes HH, 3.35% fixed-rate, due March 2023		1,250.0			1,250.0
Senior Notes JJ, 3.90% fixed-rate, due February 2024		850.0			--
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150.0			--
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes W, 7.55% fixed-rate, due April 2038		399.6			399.6
Senior Notes R, 6.125% fixed-rate, due October 2039		600.0			600.0
Senior Notes Z, 6.45% fixed-rate, due September 2040		600.0			600.0
Senior Notes BB, 5.95% fixed-rate, due February 2041		750.0			750.0
Senior Notes DD, 5.70% fixed-rate, due February 2042		600.0			600.0
Senior Notes EE, 4.85% fixed-rate, due August 2042		750.0			750.0
Senior Notes GG, 4.45% fixed-rate, due February 2043		1,100.0			1,100.0
Senior Notes II, 4.85% fixed-rate, due March 2044		1,400.0			1,000.0
Senior Notes KK, 5.10% fixed-rate, due February 2045		1,150.0			--
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			--
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		0.3			0.3
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		19,856.5			15,825.0
EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 (2)		550.0			550.0
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 (3)		285.8			285.8
EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068 (4)		682.7			682.7
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067		14.2			14.2
Total principal amount of senior and junior debt obligations		21,389.2			17,357.7
Other, non-principal amounts		(25.4	)		(6.2	)
Less current maturities of debt (5)		(2,206.4	)		(1,125.0	)
Total long-term debt	$	19,157.4		$	16,226.5

(1) Principal amounts outstanding at December 31, 2014 have interest rates ranging from 0.22% and 0.77% and are due in January 2015. (2) Fixed rate of 8.375% through August 1, 2016; thereafter, variable rate based on 3-month LIBOR plus 3.7075%. (3) Fixed rate of 7.00% through September 1, 2017; thereafter, variable rate based on 3-month LIBOR plus 2.7775%. (4) Fixed rate of 7.034% through January 15, 2018; thereafter, the rate will be the greater of 7.034% or a variable rate based on 3-month LIBOR plus 2.68%. (5) We expect to refinance the current maturities of our debt obligations at or prior to their maturity.

The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at December 31, 2014 for the next five years, and in total thereafter:

			Scheduled Maturities of Debt
	Total		2015		2016		2017		2018		2019		Thereafter
Commercial Paper	$	906.5	$	906.5	$	--	$	--	$	--	$	--	$	--
Senior Notes		18,950.0		1,300.0		750.0		800.0		350.0		1,500.0		14,250.0
Junior Subordinated Notes		1,532.7		--		--		--		--		--		1,532.7
Total	$	21,389.2	$	2,206.5	$	750.0	$	800.0	$	350.0	$	1,500.0	$	15,782.7

Parent-Subsidiary Guarantor Relationships

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full and unconditional repayment of that obligation.

EPO Debt Obligations

Commercial Paper Notes. In August 2012, EPO established a commercial paper program under which it may issue (and have outstanding at any time) up to $2.0 billion in the aggregate of short-term commercial paper notes. We intend to maintain a minimum available borrowing capacity under EPO's $3.5 Billion Multi-Year Revolving Credit Facility equal to any amount outstanding under commercial paper notes as a back-stop to the program. All commercial paper notes issued under the program are senior unsecured obligations of EPO that are unconditionally guaranteed by Enterprise Products Partners L.P.

$1.5 Billion 364-Day Credit Agreement. In September 2014, EPO entered into a new 364-Day Revolving Credit Agreement (the "$1.5 Billion 364-Day Credit Agreement"). Under the terms of the $1.5 Billion 364-Day Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO's election) at a variable interest rate for a term of 364 days, subject to the terms and conditions set forth therein. On October 1, 2014, we borrowed $1.5 billion under this facility to partially fund the cash consideration paid under Step 1 of the Oiltanking acquisition (see Note 10). This amount was subsequently repaid using proceeds from the issuance of senior notes in October 2014.

To the extent that principal amounts are outstanding, EPO's obligations under the $1.5 Billion 364-Day Credit Agreement are not secured by any collateral; however, they are guaranteed by Enterprise Products Partners L.P. Any amounts borrowed under the $1.5 Billion 364-Day Credit Agreement mature on September 29, 2015, although EPO may, between 15 and 60 days prior to the maturity date, elect to have the entire principal balance then outstanding continued as non-revolving term loans for a period of one additional year, payable on September 29, 2016.

The $1.5 Billion 364-Day Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under the $1.5 Billion 364-Day Credit Agreement. The $1.5 Billion 364-Day Credit Agreement also restricts EPO's ability to pay cash distributions to its parent, Enterprise Products Partners L.P., if a default or an event of default (as defined in the $1.5 Billion 364-Day Credit Agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.

$3.5 Billion Multi-Year Revolving Credit Facility. In June 2013, EPO amended the terms of its $3.5 Billion Multi-Year Revolving Credit Facility to, among other things, extend the maturity date of commitments under the agreement from September 2016 to June 2018 and lower the applicable margin on borrowings. Borrowings under this revolving credit facility may be used for working capital, capital expenditures, acquisitions and general company purposes.

As defined by the credit agreement, variable interest rates charged under this revolving credit facility bear interest at LIBOR plus an applicable margin. In addition, EPO is required to pay a quarterly facility fee on each lender's commitment irrespective of commitment usage. This revolving credit facility allows us to request up to two one-year extensions of the maturity date, subject to lender approval. The total amount of the bank commitments may be increased, without the consent of the lenders, by an amount not exceeding $500 million by adding one or more lenders to the facility and/or requesting that the commitments of existing lenders be increased.

The revolving credit facility contains certain financial and other customary affirmative and negative covenants. The credit agreement also restricts EPO's ability to pay cash distributions to Enterprise Products Partners L.P. if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid. EPO's borrowings under this revolving credit facility are unsecured general obligations that are guaranteed by Enterprise Products Partners L.P. and are non-recourse to Enterprise GP.

Senior Notes. EPO's fixed-rate senior notes are unsecured obligations of EPO that rank equal with its existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. EPO's senior notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict its ability (with certain exceptions) to incur debt secured by liens and engage in sale and leaseback transactions. In total, EPO issued $4.75 billion, $2.25 billion and $2.5 billion of senior notes during the years ended December 31, 2014, 2013 and 2012, respectively.

In February 2014, EPO issued $850 million in principal amount of 3.90% senior notes due February 2024 ("Senior Notes JJ") and $1.15 billion in principal amount of 5.10% senior notes due February 2045 ("Senior Notes KK"). Senior Notes JJ were issued at 99.811% of their principal amount and Senior Notes KK were issued at 99.845% of their principal amount. Net proceeds from the issuance of Senior Notes JJ and KK were used to repay debt, including amounts then outstanding under EPO's commercial paper program (which EPO used to repay $500 million in principal amount of Senior Notes O that matured in January 2014) and for general company purposes.

In October 2014, EPO issued $800 million in principal amount of 2.55% senior notes due October 2019 ("Senior Notes LL"), $1.15 billion in principal amount of 3.75% senior notes due February 2025 ("Senior Notes MM") and $400 million in principal amount of 4.95% senior notes due October 2054 ("Senior Notes NN"). Senior Notes LL, MM and NN were issued at 99.981%, 99.681% and 98.356% of their principal amounts, respectively. EPO also issued an additional $400 million in principal amount of its 4.85% Senior Notes II due March 2044. The additional Senior Notes II were issued at 100.836% of their principal amount. Net proceeds from the issuance of these senior notes were used as follows: (i) to repay debt principal amounts outstanding under EPO's $1.5 Billion 364-Day Credit Agreement and commercial paper program (both of which were used to partially fund the cash consideration paid in Step 1 of the Oiltanking acquisition), (ii) to repay $650 million in principal amount of Senior Notes G that matured in October 2014, and (iii) for general company purposes.

Junior Subordinated Notes. EPO's payment obligations under its junior notes are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement). Enterprise Products Partners L.P. guarantees repayment of amounts due under these junior notes through an unsecured and subordinated guarantee. The indenture agreement governing these notes allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. Subject to certain exceptions, during any period in which interest payments are deferred, neither we nor EPO can declare or make any distributions on any of our respective equity securities or make any payments on indebtedness or other obligations that rank equal with or are subordinate to our junior notes. Each series of our junior notes rank equal with each other. Generally, each series of junior notes are not redeemable by EPO absent payment of a make-whole premium (while such notes bear interest at a fixed annual rate).

In connection with the issuance of each series of junior notes, EPO entered into separate Replacement Capital Covenants in favor of covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed, for the benefit of such debt holders, that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities.

The following table summarizes the interest rate terms of our junior subordinated notes:

Series	Fixed Annual Interest Rate	Variable Annual Interest Rate Thereafter
Junior Subordinated Notes A	8.375% through August 2016 (1)	3-month LIBOR rate + 3.708% (4)
Junior Subordinated Notes B	7.034% through January 2018 (2)	Greater of: (i) 3-month LIBOR rate + 2.68% or (ii) 7.034% (5)
Junior Subordinated Notes C	7.00% through September 2017 (3)	3-month LIBOR rate + 2.778% (6)
(1) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007. (2) Interest is payable semi-annually in arrears in January and July of each year, which commenced in January 2008. (3) Interest is payable semi-annually in arrears in June and December of each year, which commenced in December 2009. (4) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. (5) Interest is payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. (6) Interest is payable quarterly in arrears in March, June, September and December of each year commencing in June 2017.

Letters of Credit

At December 31, 2014, EPO had $2.5 million of letters of credit outstanding related to operations at our facilities and motor fuel tax obligations.

Lender Financial Covenants

We were in compliance with the financial covenants of our consolidated debt agreements at December 31, 2014.

Information Regarding Variable Interest Rates Paid

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the year ended December 31, 2014:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
EPO $3.5 Billion Multi-Year Revolving Credit Facility	1.13% to 1.14%	1.13%
EPO $1.5 Billion 364-Day Credit Agreement	1.15% to 1.15%	1.15%

Equity and Distributions

12 Months Ended

Dec. 31, 2014

Equity and Distributions [Abstract]

Equity and Distributions

Note 13. Equity and Distributions

Partners Equity

Partners' equity reflects the various classes of limited partner interests (i.e., common units, including restricted common units, and Class B units) that we have outstanding. The following table summarizes changes in the number of Enterprise's outstanding units since December 31, 2011:

	Common Units (Unrestricted)			Restricted Common Units			Total Common Units
Number of units outstanding at December 31, 2011		1,755,504,404			7,736,432			1,763,240,836
Common units issued in connection with underwritten offering		18,400,000			--			18,400,000
Common units issued in connection with at-the-market program		7,957,090			--			7,957,090
Common units issued in connection with DRIP and EUPP		5,629,320			--			5,629,320
Common units issued in connection with the vesting and exercise of unit options		427,828			--			427,828
Common units issued in connection with the vesting of restricted common unit awards		2,633,206			(2,633,206	)		--
Common units issued in connection with the vesting of other types of equity-based awards		104,336			--			104,336
Restricted common unit awards issued		--			3,177,476			3,177,476
Forfeiture of restricted common unit awards		--			(493,730	)		(493,730	)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards		(816,482	)		--			(816,482	)
Number of units outstanding at December 31, 2012		1,789,839,702			7,786,972			1,797,626,674
Common units issued in connection with underwritten offering		36,800,000			--			36,800,000
Common units issued in connection with at-the-market program		15,249,378			--			15,249,378
Common units issued in connection with DRIP and EUPP		10,308,254			--			10,308,254
Common units issued in connection with the vesting and exercise of unit options		401,764			--			401,764
Common units issued in connection with the vesting of restricted common unit awards		3,770,696			(3,770,696	)		--
Conversion and reclassification of Class B units to common units		9,040,862			--			9,040,862
Restricted common unit awards issued		--			3,549,052			3,549,052
Forfeiture of restricted common unit awards		--			(344,114	)		(344,114	)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards		(1,261,854	)		--			(1,261,854	)
Number of units outstanding at December 31, 2013		1,864,148,802			7,221,214			1,871,370,016
Common units issued in connection with at-the-market program		1,590,334			--			1,590,334
Common units issued in connection with DRIP and EUPP		9,754,227			--			9,754,227
Common units issued in connection with Step 1 of Oiltanking acquisition		54,807,352			--			54,807,352
Common units issued in connection with the vesting and exercise of unit options		1,014,108			--			1,014,108
Common units issued in connection with the vesting of phantom unit awards		23,311			--			23,311
Common units issued in connection with the vesting of restricted common unit awards		2,634,074			(2,634,074	)		--
Forfeiture of restricted common unit awards		--			(357,350	)		(357,350	)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards		(894,383	)		--			(894,383	)
Other		17,202			--			17,202
Number of units outstanding at December 31, 2014		1,933,095,027			4,229,790			1,937,324,817

Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Sixth Amended and Restated Agreement of Limited Partnership (as amended from time to time, the "Partnership Agreement"). We are managed by our general partner, Enterprise GP.

In accordance with our Partnership Agreement, capital accounts are maintained for our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity amounts presented in our consolidated financial statements prepared in accordance with GAAP. Earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests.

In June 2013, we filed with the SEC a new universal shelf registration statement (the "2013 Shelf") that replaced our prior universal shelf registration statement filed with the SEC in July 2010 (the "2010 Shelf"). The 2013 Shelf allows (and the prior 2010 Shelf allowed) Enterprise Products Partners L.P. and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. We used the 2013 Shelf and 2010 Shelf to facilitate the following securities offerings:

We used the 2010 Shelf to issue 18,400,000 common units to the public (including an over-allotment amount of 2,400,000 common units) at an offering price of $26.54 per unit in September 2012, which generated total net cash proceeds of $473.3 million. In addition, EPO issued $2.5 billion of unsecured senior notes during 2012 using the 2010 Shelf.

We used the 2010 Shelf to issue 18,400,000 common units to the public (including an over-allotment amount of 2,400,000 common units) at an offering price of $27.28 per unit in February 2013, which generated net cash proceeds of $486.6 million. In addition, EPO issued $2.25 billion of unsecured senior notes during 2013 using the 2010 Shelf.

§	We used the 2013 Shelf to issue 18,400,000 common units to the public (including an over-allotment amount of 2,400,000 common units) at an offering price of $31.03 per unit in November 2013, which generated net cash proceeds of $553.0 million.

§	We used the 2013 Shelf to issue $4.75 billion of unsecured senior notes during 2014 (see Note 12).

In October 2013, we filed a registration statement with the SEC covering the issuance of up to $1.25 billion of our common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of such offerings. Pursuant to this "at-the-market" program, we may sell common units under an equity distribution agreement between Enterprise Products Partners L.P. and certain broker-dealers from time-to-time by means of ordinary brokers' transactions through the NYSE at market prices, in block transactions or as otherwise agreed to with the broker-dealer parties to the agreement. The new registration statement was declared effective on October 15, 2013 and replaced our prior registration statement with respect to the at-the-market program, which was filed with the SEC in March 2012 and covered the issuance of up to $1.0 billion of our common units.

During 2014, we issued 1,590,334 common units under our at-the-market program for aggregate gross cash proceeds of $58.3 million, resulting in total net cash proceeds of $57.7 million. During 2013, we issued 15,249,378 common units under our at-the-market program for aggregate gross cash proceeds of $460.4 million, resulting in total net cash proceeds of $456.3 million. During 2012, we issued 7,957,090 common units under this program for aggregate gross cash proceeds of $205.4 million, resulting in total net cash proceeds of $203.8 million. After taking into account the aggregate sales price of common units sold under our at-the-market program through December 31, 2014, we have the capacity to issue additional common units under this program up to an aggregate sales price of $1.19 billion.

We also have registration statements on file with the SEC collectively authorizing the issuance of up to 140,000,000 of our common units in connection with a distribution reinvestment plan (or "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 our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional new common units. After taking into account the number of common units issued under the DRIP through December 31, 2014, we have the capacity to issue an additional 27,481,349 common units under this plan. Activity under our DRIP for the last three fiscal years was as follows: 9,480,407 common units issued during 2014, which generated net cash proceeds of $321.3 million; 10,024,828 common units issued during 2013, which generated net cash proceeds of $287.6 million; and 5,359,696 common units issued during 2012, which generated net cash proceeds of $132.6 million.

During 2014, privately held affiliates of EPCO reinvested $100.0 million, resulting in the issuance of 2,946,241 common units under our DRIP (this amount being a component of the total common units issued under the DRIP for the year ended December 31, 2014).

In addition to the DRIP, we have registration statements on file with the SEC authorizing the issuance of up to 8,000,000 of our common units in connection with an employee unit purchase plan (or "EUPP"). After taking into account the number of common units issued under the EUPP through December 31, 2014, we may issue an additional 7,153,068 common units under this plan. Activity under our EUPP for the last three fiscal years was as follows: 273,820 common units issued during 2014, which generated net cash proceeds of $9.8 million; 283,426 common units issued during 2013, which generated net cash proceeds of $8.5 million; and 269,624 common units issued during 2012, which generated net cash proceeds of $7.1 million.

The net cash proceeds we received from the issuance of common units during the year ended December 31, 2014 were used to temporarily reduce amounts outstanding under EPO's commercial paper program and for general company purposes.

Registration Rights Agreement. In order to fund the equity consideration paid in Step 1 of the Oiltanking acquisition (see Note 10), we issued 54,807,352 common units to OTA on October 1, 2014 in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"), pursuant to Section 4(a)(2) thereof, and we granted OTA registration rights with respect to these common units under a Registration Rights Agreement between us and OTA (the "Registration Rights Agreement"). The Registration Rights Agreement provides that, subject to the terms and conditions set forth therein, at any time after the earlier of (i) 90 days after October 1, 2014 and (ii) the execution of definitive agreements to acquire (through merger or otherwise) all or substantially all of the Oiltanking common units not owned by Enterprise or its affiliates, OTA may request that we prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of the 54,807,352 Enterprise common units that OTA owns. Our obligation to OTA to effect such transactions is limited to five registration statements and underwritten offerings.

Class B Units. In connection with the TEPPCO Merger in October 2009, a privately held affiliate of EPCO exchanged a portion of its TEPPCO units (based on a 1.24 exchange ratio) for 9,040,862 of our Class B units in lieu of receiving common units. The Class B units automatically converted into the same number of common units on the date immediately following the payment date for the sixteenth regular quarterly distribution following the closing date of the TEPPCO Merger. The Class B units were entitled to vote together with our common units as a single class on partnership matters and generally had the same rights and privileges as our common units, except that the Class B units were not entitled to receive regular quarterly cash distributions until they automatically converted into an equal number of common units on August 8, 2013.

Treasury Units. In December 1998, we announced a common unit repurchase program whereby we, together with certain affiliates, intended to repurchase up to 4,000,000 of our common units. A total of 2,763,200 common units were repurchased under this program; however, no repurchases have been made since 2002. As of December 31, 2014, we and our affiliates could repurchase up to 1,236,800 additional common units under this program.

A total of 2,634,074 restricted common unit awards granted to employees of EPCO vested and converted to common units during the year ended December 31, 2014. Of this amount, 894,383 were sold back to us by employees to cover related withholding tax requirements. The total cost of these treasury unit purchases was approximately $30.2 million. We cancelled such treasury units immediately upon acquisition. See Note 5 for additional information regarding our equity-based awards.

Two-for-One Split of Limited Partner Units. In July 2014, we announced that our general partner approved a two-for-one split of our common units. The common unit split was completed on August 21, 2014 by distributing one additional common unit for each common unit outstanding (to holders of record as of the close of business on August 14, 2014). All per unit amounts and number of Enterprise units outstanding in this annual report are presented on a post-split basis.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive income (loss) primarily reflects the effective portion of the gain or loss on derivative instruments designated and qualified as cash flow hedges. Gain or loss amounts related to cash flow hedges recorded in accumulated other comprehensive income (loss) are reclassified to earnings in the same period(s) in which the underlying hedged forecasted transactions affect earnings. If it becomes probable that a forecasted transaction will not occur, the related net gain or loss in accumulated other comprehensive income (loss) is immediately reclassified into earnings.

The following tables present the components of accumulated other comprehensive income (loss) as reported on our Consolidated Balance Sheets at the dates indicated:

	Gains (Losses) on Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other		Total
Balance, December 31, 2012	$	10.1		$	(383.0	)	$	2.5	$	(370.4	)
Other comprehensive income before reclassifications		(46.9	)		6.6			0.4		(39.9	)
Amounts reclassified from accumulated other comprehensive loss		22.1			29.2			--		51.3
Total other comprehensive income (loss)		(24.8	)		35.8			0.4		11.4
Balance, December 31, 2013		(14.7	)		(347.2	)		2.9		(359.0	)
Other comprehensive income before reclassifications		161.3			--			0.4		161.7
Amounts reclassified from accumulated other comprehensive (income) loss		(76.7	)		32.4			--		(44.3	)
Total other comprehensive income		84.6			32.4			0.4		117.4
Balance, December 31, 2014	$	69.9		$	(314.8	)	$	3.3	$	(241.6	)

The following table presents reclassifications out of accumulated other comprehensive income (loss) into net income for the periods indicated:

		For the Year Ended December 31,
	Location	2014			2013
Losses (gains) on cash flow hedges:
Interest rate derivatives	Interest expense	$	32.4		$	29.2
Commodity derivatives	Revenue		(75.0	)		22.4
Commodity derivatives	Operating costs and expenses		(1.7	)		(0.3	)
Total		$	(44.3	)	$	51.3

Noncontrolling Interests

Noncontrolling interests as presented on our Consolidated Financial Statements represent third party ownership interests in joint ventures that we consolidate for financial reporting purposes, including Oiltanking, Tri-States NGL Pipeline L.L.C., Independence Hub LLC, Rio Grande Pipeline Company, Wilprise Pipeline Company LLC and Enterprise EF78 LLC.

In October 2014, we recorded $1.4 billion of noncontrolling interests in connection with Step 1 of the Oiltanking acquisition. In February 2015, we acquired these noncontrolling interests in connection with the consummation of the Oiltanking Merger. See Note 10 for a discussion of these matters. Cash distributions paid in the fourth quarter of 2014 to the limited partners of Oiltanking other than EPO and its subsidiaries are presented as amounts paid to noncontrolling interests.

In June 2013, we formed a joint venture, Enterprise EF78 LLC, with Western Gas Partners, LP ("Western Gas") involving two NGL fractionators at our complex in Mont Belvieu, Texas. We own 75% of the joint venture's membership interests and consolidate the joint venture. Western Gas acquired a 25% noncontrolling interest in the joint venture for an initial contribution of $90.2 million. The initial contribution and subsequent contributions to fund construction are reflected as cash contributions from noncontrolling interests on our Statements of Consolidated Cash Flows.

The following table presents additional information regarding noncontrolling interests as presented on our Consolidated Balance Sheets at the dates indicated:

	December 31,
	2014			2013
Limited partners of Oiltanking other than EPO		$	1,408.9		$	--
Joint venture partners			220.1			225.6
Total		$	1,629.0		$	225.6

The following table presents the components of net income attributable to noncontrolling interests as presented on our Statements of Consolidated Operations for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Limited partners of Oiltanking other than EPO		$	14.2		$	--		$	--
Joint venture partners			31.9			10.2			8.1
Total		$	46.1		$	10.2		$	8.1

The following table presents cash distributions paid to and cash contributions received from noncontrolling interests as presented on our Statements of Consolidated Cash Flows and Statements of Consolidated Equity for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Cash distributions paid to noncontrolling interests:
Limited partners of Oiltanking other than EPO	$	7.7	$	--	$	--
Joint venture partners		40.9		8.9		13.3
Total	$	48.6	$	8.9	$	13.3

Cash contributions from noncontrolling interests:
Joint venture partners	$	4.0	$	115.4	$	6.6

Cash Distributions

The following table presents Enterprise's declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter.

	Distribution Per Common Unit		Record Date	Payment Date
2013:
1st Quarter	$	0.3350	4/30/2013	5/7/2013
2nd Quarter	$	0.3400	7/31/2013	8/7/2013
3rd Quarter	$	0.3450	10/31/2013	11/7/2013
4th Quarter	$	0.3500	1/31/2014	2/7/2014
2014:
1st Quarter	$	0.3550	4/30/2014	5/7/2014
2nd Quarter	$	0.3600	7/31/2014	8/7/2014
3rd Quarter	$	0.3650	10/31/2014	11/7/2014
4th Quarter	$	0.3700	1/30/2015	2/6/2015

As previously noted, 9,040,862 Class B units automatically converted into an equal number of distribution-bearing common units on August 8, 2013.

In November 2010, we completed our merger with Enterprise GP Holdings L.P. (the "Holdings Merger"). In connection with the Holdings Merger, a privately held affiliate of EPCO agreed to temporarily waive the regular quarterly cash distributions it would otherwise receive from us with respect to a certain number of our common units it owns (the "Designated Units"). Distributions paid to partners during calendar years 2012, 2013 and 2014 excluded 52,260,000, 47,400,000 and 45,120,000 Designated Units, respectively. Distributions to be paid, if any, during calendar year 2015 will exclude 35,380,000 common units.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Business Segments

12 Months Ended

Dec. 31, 2014

Business Segments [Abstract]

Business Segments

Note 14. Business Segments

We have five reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold. Financial information regarding these segments is evaluated regularly by our chief operating decision makers in deciding how to allocate resources and in assessing operating and financial performance. The chief executive officer and chief operating officer of our general partner have been identified as our chief operating decision makers. While these two officers evaluate results in a number of different ways, the business segment structure is the primary basis for which the allocation of resources and financial results are assessed.

The following information summarizes the current assets and operations of each business segment (mileage and other statistics are unaudited):

Our NGL Pipelines & Services business segment includes our natural gas processing plants and related NGL marketing activities; approximately 19,300 miles of NGL pipelines; NGL and related product storage facilities; and 15 NGL fractionators. This segment also includes our NGL import and LPG export terminal operations.

Our Onshore Natural Gas Pipelines & Services business segment includes approximately 19,300 miles of onshore natural gas pipeline systems that provide for the gathering and transportation of natural gas in Colorado, Louisiana, New Mexico, Texas and Wyoming. We lease underground salt dome natural gas storage facilities located in Texas and Louisiana and own an underground salt dome storage cavern in Texas, all of which are important to our natural gas pipeline operations. This segment also includes our related natural gas marketing activities.

Our Onshore Crude Oil Pipelines & Services business segment includes approximately 5,400 miles of onshore crude oil pipelines, crude oil storage terminals located in Oklahoma and Texas, and our crude oil marketing activities. This business also includes a fleet of approximately 560 tractor-trailer tank trucks, the majority of which we lease and operate, used to transport crude oil for us and third parties.

Our Offshore Pipelines & Services business segment serves some of the most active drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. This segment includes approximately 2,350 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms.

Our Petrochemical & Refined Products Services business segment includes (i) propylene fractionation and related operations, including approximately 680 miles of pipelines; (ii) a butane isomerization complex, associated deisobutanizer units and related pipeline assets; (iii) octane enhancement and high purity isobutylene production facilities; (iv) refined products pipelines aggregating approximately 4,200 miles and related marketing activities; and (v) marine transportation.

All activities included in our former sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our previously held investment in Energy Transfer Equity. See Note 9 for information regarding the liquidation of our investment in Energy Transfer Equity.

Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Our consolidated revenues reflect the elimination of intercompany transactions. Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base.

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 executive 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.

In total, gross operating margin represents operating income exclusive of (1) depreciation, amortization and accretion expenses, (2) impairment charges, (3) gains and losses attributable to asset sales and insurance recoveries and (4) general and administrative costs. Gross operating margin includes equity in income of unconsolidated affiliates and non-refundable deferred transportation revenues relating to the make-up rights of committed shippers associated with certain pipelines. 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, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests.

We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Equity investments with industry partners are a significant component of our business strategy. They are a means by which we conduct our operations to align our interests with those of customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed. Many of these businesses perform supporting or complementary roles to our other midstream business operations.

Our integrated midstream energy asset network (including the midstream energy assets owned by our equity method investees) provides services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. In general, hydrocarbons may enter our asset system in a number of ways, such as through an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an onshore natural gas gathering pipeline, an onshore crude oil pipeline or terminal, an NGL fractionator, an NGL storage facility or an NGL gathering or transportation pipeline. Many of our equity investees are included within our integrated midstream asset network. For example, we have ownership interests in several offshore Gulf of Mexico natural gas and crude oil pipelines. Other examples include our use of the Promix NGL fractionator to process mixed NGLs extracted by our natural gas processing plants and our use of the Texas Express Pipeline to transport mixed NGLs to our Mont Belvieu complex. Given the integral nature of our equity method investees to our operations, we believe the presentation of equity earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate.

Segment assets consist of property, plant and equipment, investments in unconsolidated affiliates, intangible assets and goodwill. The carrying values of such amounts are assigned to each segment based on each asset's or investment's principal operations and contribution to the gross operating margin of that particular segment. Since construction-in-progress amounts (a component of property, plant and equipment) generally do not contribute to segment gross operating margin, such amounts are excluded from segment asset totals until the underlying assets are placed in service. Intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate. Substantially all of our plants, pipelines and other fixed assets are located in the U.S.

The results of operations from our liquids pipelines are primarily dependent upon the volumes transported and the associated fees we charge for such transportation services. Typically, pipeline transportation revenue is recognized when volumes are re-delivered to customers. However, under certain pipeline transportation agreements, customers are required to ship a minimum volume over an agreed-upon period. These arrangements typically entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper "make-up rights"). Revenue pursuant to such agreements, including that associated with make-up rights, is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation.

However, management includes deferred transportation revenues relating to the "make-up rights" of committed shippers when reviewing the financial results of certain major new pipeline projects such as ATEX. From an internal (and segment) reporting standpoint, management considers the transportation fees paid by committed shippers on major new pipeline projects, including any non-refundable revenues that may be deferred under GAAP related to make-up rights, to be important in assessing the financial performance of these pipeline assets. Since management includes these deferred revenues in non-GAAP gross operating margin, these amounts are deducted in determining GAAP-based operating income. Our consolidated revenues do not reflect any deferred revenues until the conditions for recognizing such revenues are met in accordance with GAAP.

Several of our major new liquids pipeline projects experienced periods in 2013 and 2014 where shippers were unable to meet their contractual minimum volume commitments. In general, we expect that these types of shortfalls will continue in 2015 due to the current business environment, with the recognition of revenue associated with past deferrals associated with make-up rights partially or entirely offsetting any new make-up right deferrals.

The following table presents our measurement of non-GAAP total segment gross operating margin for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Revenues	$	47,951.2		$	47,727.0		$	42,583.1
Subtract operating costs and expenses		(44,220.5	)		(44,238.7	)		(39,367.9	)
Add equity in income of unconsolidated affiliates		259.5			167.3			64.3
Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin		1,282.7			1,148.9			1,061.7
Add impairment charges not reflected in gross operating margin		34.0			92.6			63.4
Subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin		(102.1	)		(83.4	)		(17.6	)
Add non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin (1)		84.6			4.4			--
Subtract subsequent recognition of deferred revenues attributable to make-up rights		(2.9	)		--			--
Total segment gross operating margin	$	5,286.5		$	4,818.1		$	4,387.0

(1) Several of our major new liquids pipeline projects experienced periods in 2013 and 2014 where shippers were unable to meet their contractual minimum volume commitments.

The following table presents a reconciliation of total segment gross operating margin to operating income and further to income before income taxes for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Total segment gross operating margin	$	5,286.5		$	4,818.1		$	4,387.0
Adjustments to reconcile total segment gross operating margin to operating income:
Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin		(1,282.7	)		(1,148.9	)		(1,061.7	)
Subtract impairment charges not reflected in gross operating margin		(34.0	)		(92.6	)		(63.4	)
Add net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin (see Note 20)		102.1			83.4			17.6
Subtract non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin		(84.6	)		(4.4	)		--
Add subsequent recognition of deferred revenues attributable to make-up rights		2.9			--			--
Subtract general and administrative costs not reflected in gross operating margin		(214.5	)		(188.3	)		(170.3	)
Operating income		3,775.7			3,467.3			3,109.2
Other expense, net		(919.1	)		(802.7	)		(698.4	)
Income before income taxes	$	2,856.6		$	2,664.6		$	2,410.8

Information by business segment, together with reconciliations to our consolidated financial statement totals, is presented in the following table:

	Reportable Business Segments
	NGL Pipelines & Services		Onshore Natural Gas Pipelines & Services		Onshore Crude Oil Pipelines & Services		Offshore Pipelines & Services		Petrochemical & Refined Products Services			Other Investments		Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Year ended December 31, 2014	$	17,078.4	$	4,182.6	$	20,151.9	$	150.3	$	6,316.5		$	--	$	--		$	47,879.7
Year ended December 31, 2013		17,119.1		3,522.7		20,609.1		151.7		6,258.5			--		--			47,661.1
Year ended December 31, 2012		15,158.9		3,297.7		17,661.6		182.7		6,208.9			--		--			42,509.8
Revenues from related parties:
Year ended December 31, 2014		11.4		21.2		32.4		6.5		--			--		--			71.5
Year ended December 31, 2013		1.1		15.8		41.3		7.7		--			--		--			65.9
Year ended December 31, 2012		9.5		54.9		0.1		8.8		--			--		--			73.3
Intersegment and intrasegment revenues:
Year ended December 31, 2014		13,716.5		1,106.7		12,678.7		6.5		1,779.6			--		(29,288.0	)		--
Year ended December 31, 2013		11,096.6		959.7		10,222.3		9.6		1,764.0			--		(24,052.2	)		--
Year ended December 31, 2012		12,500.6		871.6		6,906.9		10.4		1,758.9			--		(22,048.4	)		--
Total revenues:
Year ended December 31, 2014		30,806.3		5,310.5		32,863.0		163.3		8,096.1			--		(29,288.0	)		47,951.2
Year ended December 31, 2013		28,216.8		4,498.2		30,872.7		169.0		8,022.5			--		(24,052.2	)		47,727.0
Year ended December 31, 2012		27,669.0		4,224.2		24,568.6		201.9		7,967.8			--		(22,048.4	)		42,583.1
Equity in income (loss) of unconsolidated affiliates:
Year ended December 31, 2014		30.6		3.6		184.6		54.0		(13.3	)		--		--			259.5
Year ended December 31, 2013		15.7		3.8		140.3		29.8		(22.3	)		--		--			167.3
Year ended December 31, 2012		15.9		4.4		32.6		26.9		(17.9	)		2.4		--			64.3
Gross operating margin:
Year ended December 31, 2014		2,877.7		803.3		762.5		162.0		681.0			--		--			5,286.5
Year ended December 31, 2013		2,514.4		789.0		742.7		146.1		625.9			--		--			4,818.1
Year ended December 31, 2012		2,468.5		775.5		387.7		173.0		579.9			2.4		--			4,387.0
Property, plant and equipment, net: (see Note 8)
At December 31, 2014		11,766.9		8,835.5		2,332.2		1,145.1		3,047.2			--		2,754.7			29,881.6
At December 31, 2013		9,957.8		8,917.3		1,479.9		1,223.7		2,712.4			--		2,655.5			26,946.6
At December 31, 2012		8,494.8		8,950.1		1,385.9		1,343.0		2,559.5			--		2,113.1			24,846.4
Investments in unconsolidated affiliates: (see Note 9)
At December 31, 2014		682.3		23.2		1,767.7		493.7		75.1			--		--			3,042.0
At December 31, 2013		645.5		24.2		1,165.2		531.8		70.4			--		--			2,437.1
At December 31, 2012		324.6		24.9		493.8		479.0		72.3			--		--			1,394.6
Intangible assets, net: (see Note 11)
At December 31, 2014		689.2		972.9		2,223.6		41.6		374.8			--		--			4,302.1
At December 31, 2013		285.2		1,017.8		4.5		54.7		100.0			--		--			1,462.2
At December 31, 2012		320.6		1,067.9		5.9		66.2		106.2			--		--			1,566.8
Goodwill: (see Note 11)
At December 31, 2014		2,180.4		296.3		859.9		82.0		781.3			--		--			4,199.9
At December 31, 2013		341.2		296.3		305.1		82.1		1,055.3			--		--			2,080.0
At December 31, 2012		341.2		296.3		311.2		82.1		1,056.0			--		--			2,086.8
Segment assets:
At December 31, 2014		15,318.8		10,127.9		7,183.4		1,762.4		4,278.4			--		2,754.7			41,425.6
At December 31, 2013		11,229.7		10,255.6		2,954.7		1,892.3		3,938.1			--		2,655.5			32,925.9
At December 31, 2012		9,481.2		10,339.2		2,196.8		1,970.3		3,794.0			--		2,113.1			29,894.6

The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
NGL Pipelines & Services:
Sales of NGLs and related products	$	15,460.1		$	15,916.0		$	14,218.5
Midstream services		1,629.7			1,204.2			949.9
Total		17,089.8			17,120.2			15,168.4
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		3,181.7			2,571.6			2,395.4
Midstream services		1,022.1			966.9			957.2
Total		4,203.8			3,538.5			3,352.6
Onshore Crude Oil Pipelines & Services:
Sales of crude oil		19,783.9			20,371.3			17,548.7
Midstream services		400.4			279.1			113.0
Total		20,184.3			20,650.4			17,661.7
Offshore Pipelines & Services:
Sales of natural gas		0.3			0.5			0.4
Sales of crude oil		8.6			5.7			3.3
Midstream services		147.9			153.2			187.8
Total		156.8			159.4			191.5
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		5,575.5			5,568.8			5,470.9
Midstream services		741.0			689.7			738.0
Total		6,316.5			6,258.5			6,208.9
Total consolidated revenues	$	47,951.2		$	47,727.0		$	42,583.1

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales	$	40,464.1		$	40,770.2		$	36,015.5
Other operating costs and expenses (1)		2,541.8			2,310.4			2,244.9
Depreciation, amortization and accretion		1,282.7			1,148.9			1,061.7
Net gains attributable to asset sales and insurance recoveries		(102.1	)		(83.4	)		(17.6	)
Non-cash asset impairment charges		34.0			92.6			63.4
General and administrative costs		214.5			188.3			170.3
Total consolidated costs and expenses	$	44,435.0		$	44,427.0		$	39,538.2

(1) Represents cost of operating our plants, pipelines and other fixed assets, excluding depreciation, amortization and accretion charges.

Fluctuations in our product sales revenues and related cost of sales amounts are explained in part by changes in energy commodity prices. In general, lower energy commodity prices result in a decrease in our revenues attributable to product sales; however, these lower commodity prices also decrease the associated cost of sales as purchase costs decline. The same correlation would be true in the case of higher energy commodity sales prices and purchase costs.

Our largest non-affiliated customer for 2014 was Shell Oil Company and its affiliates (collectively, "Shell"), which accounted for $4.05 billion, or 8.5%, of our consolidated revenues for the year. The following table presents our consolidated revenues from Shell by business segment for the year ended December 31, 2014:

NGL Pipelines & Services	$	615.5
Onshore Natural Gas Pipelines & Services		130.3
Onshore Crude Oil Pipelines & Services		3,106.0
Offshore Pipelines & Services		6.7
Petrochemical & Refined Products Services		194.2
Total	$	4,052.7

BP p.l.c. and its affiliates was our largest non-affiliated customer for 2013 and 2012, accounting for 9.0% and 9.5%, respectively, of our consolidated revenues for the years ended December 31, 2013 and 2012.

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Related Party Transactions

Related Party Transactions

12 Months Ended

Dec. 31, 2014

Note 15. Related Party Transactions

The following table summarizes our related party transactions for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Revenues – related parties:
Unconsolidated affiliates		$	71.5		$	65.9		$	73.3
Costs and expenses – related parties:
EPCO and affiliates		$	939.9		$	892.2		$	816.9
Unconsolidated affiliates			183.0			160.0			40.2
Total		$	1,122.9		$	1,052.2		$	857.1

The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated:

	December 31,
	2014		2013
Accounts receivable - related parties:
Unconsolidated affiliates	$	2.8	$	6.8

Accounts payable - related parties:
EPCO and affiliates	$	98.1	$	116.3
Unconsolidated affiliates		20.8		34.2
Total	$	118.9	$	150.5

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 privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies. At December 31, 2014, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts, the beneficiaries of which include the estate of Dan L. Duncan) beneficially owned the following limited partner interests in us:

Number of Units	Percentage of Total Units Outstanding
684,721,631	35.3%

We and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates depend on the cash distributions they receive from us and other investments to fund their other activities and to meet their debt obligations. During the years ended December 31, 2014, 2013 and 2012, we paid EPCO and its privately held affiliates cash distributions totaling $877.0 million, $811.4 million and $750.2 million, respectively.

From time-to-time, EPCO and its privately held affiliates elect to reinvest a portion of the cash distributions they receive from us into the purchase of additional common units under our DRIP. See Note 13 for information regarding reinvestments made during 2014.

Effective January 15, 2015, privately held affiliates of EPCO (together with their respective subsidiaries) pledged 180,000,000 of our common units that they own as security under such affiliates' credit facilities. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units. A development of this nature could affect the market price of our common units.

We lease office space from affiliates of EPCO. The rental rates in these lease agreements approximate market rates.

EPCO ASA. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA or by other service providers. We and our general partner are parties to the ASA. The significant terms of the ASA are as follows:

EPCO will provide selling, general and administrative services and management and operating services as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel.

We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time with respect to the services provided to us by EPCO.

§	EPCO will allow us to participate as a named insured in its overall insurance program, with the associated premiums and other costs being allocated to us. See Note 19 for additional information regarding our insurance programs.

Our operating costs and expenses include amounts paid to EPCO for the costs it incurs to operate our facilities, including the compensation of its employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Likewise, our general and administrative costs include amounts paid to EPCO for administrative services, including the compensation of its employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of legal or accounting salaries based on estimates of time spent on each entity's business and affairs).

The following table presents our costs and expenses attributable to the ASA and other related party transactions with EPCO for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Operating costs and expenses		$	801.7		$	770.7		$	719.4
General and administrative expenses			138.2			121.5			97.5
Total costs and expenses		$	939.9		$	892.2		$	816.9

Since the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.

Relationships with Unconsolidated Affiliates

Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. The following information summarizes significant related party transactions with our current unconsolidated affiliates:

For the years ended December 31, 2014, 2013 and 2012, we paid Seaway $130.8 million, $132.4 million and $18.1 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $29.4 and $41.3 million for the years ended December 31, 2014 and 2013, respectively.

We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $11.1 million, $9.8 million and $7.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. Expenses with Promix were $25.8 million, $28.1 million and $27.4 million for the years ended December 31, 2014, 2013 and 2012, respectively.

§	For the year ended December 31, 2014, revenues from Texas Express for the sale of NGLs were $9.1 million.

§	For the years ended December 31, 2014 and 2013, we paid Eagle Ford Pipeline LLC $25.8 million and $5.4 million, respectively, for crude oil transportation.

§	We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $24.5 million, $21.8 million and $19.4 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Prior to acquiring the remaining ownership interests in Evangeline in June 2012, we sold natural gas to Evangeline, which, in turn, used the natural gas to satisfy its supply commitments to a customer. Revenues from Evangeline were $42.9 million for the year ended December 31, 2012.

Provision for Income Taxes [Abstract]

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References + Details

Provision for Income Taxes

12 Months Ended

Dec. 31, 2014

Provision for Income Taxes

Note 16. Provision for Income Taxes

Provision for income taxes primarily reflects our state tax obligations under the Revised Texas Franchise Tax (the "Texas Margin Tax"). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

We recognized income tax expense of $23.1 million for the year ended December 31, 2014, of which $17.5 million was attributable to the Texas Margin Tax. We recognized income tax expense of $57.5 million for the year ended December 31, 2013, of which $19.6 million was attributable to certain legislative changes to the Texas Margin Tax enacted during the second quarter of 2013.

During the year ended December 31, 2012, we recognized an overall income tax benefit of $17.2 million, which was primarily due to a $45.3 million income tax benefit related to the conversion of certain of our subsidiaries to limited liability companies, partially offset by accruals for the Texas Margin Tax. The $45.3 million income tax benefit is attributable to the difference between deferred income taxes accrued by the applicable subsidiaries through the date of conversion and any current income tax due in connection with the conversions.

Our federal and state income tax provision (benefit) is summarized below:

	For the Year Ended December 31,
	2014		2013			2012
Current:
Federal	$	2.2	$	(0.5	)	$	18.9
State		13.4		19.3			28.9
Foreign		1.4		0.8			1.2
Total current		17.0		19.6			49.0
Deferred:
Federal		2.2		(0.5	)		(64.7	)
State		3.5		38.9			(1.4	)
Foreign		0.4		(0.5	)		(0.1	)
Total deferred		6.1		37.9			(66.2	)
Total provision for (benefit from) income taxes	$	23.1	$	57.5		$	(17.2	)

A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:

	For the Year Ended December 31,
	2014			2013			2012
Pre-Tax Net Book Income ("NBI")	$	2,856.6		$	2,664.6		$	2,410.8

Texas Margin Tax (1)	$	17.5		$	58.3		$	23.5
State income taxes (net of federal benefit)		0.2			(0.1	)		5.3
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		1.5			(1.4	)		(1.6	)
Valuation allowance					--			(2.0	)
Expiration of tax net operating loss		--			0.1			2.4
Tax gain on conversion of corporate subsidiaries into limited liability companies		--			--			(45.3	)
Other permanent differences		3.9			0.6			0.5
Provision for (benefit from) income taxes	$	23.1		$	57.5		$	(17.2	)

Effective income tax rate		0.8	%		2.2	%		(0.7	)%

(1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.

The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated:

	At December 31,
	2014		2013
Deferred tax assets:
Net operating loss carryovers (1)	$	0.3	$	0.1
Employee benefit plans		0.3		0.2
Accruals		1.5		2.0
Total deferred tax assets		2.1		2.3
Less: Deferred tax liabilities:
Property, plant and equipment		64.4		59.8
Equity investment in partnerships		4.1		2.9
Total deferred tax liabilities		68.5		62.7
Total net deferred tax liabilities	$	66.4	$	60.4

Current portion of total net deferred tax assets	$	0.2	$	0.4
Long-term portion of total net deferred tax liabilities	$	66.6	$	60.8

(1) These losses expire in various years between 2015 and 2028 and are subject to limitations on their utilization.

Current accounting guidance provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. We did not rely on any uncertain tax positions in recording our income tax-related amounts during the years ended December 31, 2014, 2013 or 2012.

Earnings Per Unit

12 Months Ended

Dec. 31, 2014

Earnings Per Unit [Abstract]

Earnings Per Unit

Note 17. Earnings Per Unit

Basic earnings per unit is computed by dividing net income or loss available to our common unit holders by the weighted-average number of our distribution-bearing units outstanding during a period, which excludes the Designated Units (see Note 13) to the extent such units do not participate in the distributions to be paid with respect to such period.

Diluted earnings per unit is computed by dividing net income or loss attributable to our limited partners by the sum of (i) the weighted-average number of our distribution-bearing units outstanding during a period (as used in determining basic earnings per unit), (ii) the weighted-average number of our Class B units (see Note 13) outstanding during a period, (iii) the weighted-average number of Designated Units outstanding during a period and (iv) 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, the Class B units, Designated 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 price during the period. The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.

The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:

	For the Year Ended December 31,
	2014			2013		2012
BASIC EARNINGS PER UNIT
Net income attributable to limited partners	$	2,787.4		$	2,596.9	$	2,419.9
Undistributed earnings allocated and cash payments on phantom unit awards (1)		(5.2	)		--		--
Net income available to common unitholders	$	2,782.2		$	2,596.9	$	2,419.9

Basic weighted-average number of common units outstanding		1,848.7			1,788.0		1,723.6

Basic earnings per unit	$	1.51		$	1.45	$	1.40

DILUTED EARNINGS PER UNIT
Net income attributable to limited partners	$	2,787.4		$	2,596.9	$	2,419.9

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		1,848.7			1,788.0		1,723.6
Designated Units		42.7			46.8		51.0
Class B units (2)		--			5.4		9.0
Phantom units (1)		2.9			--		--
Incremental option units		0.9			2.4		2.8
Total		1,895.2			1,842.6		1,786.4

Diluted earnings per unit	$	1.47		$	1.41	$	1.35

(1) Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to Enterprise's common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit. Phantom unit awards were first issued in February 2014. (2) The Class B units automatically converted into an equal number of distribution-bearing common units in August 2013.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 18. Commitments and Contingencies

Litigation

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from 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 fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the partnership in litigation matters.

Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued.

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Based on a consideration of all relevant known facts and circumstances, we do not believe that the ultimate outcome of any currently pending litigation directed against us will have a material impact on our consolidated financial statements either individually at the claim level or in the aggregate.

At December 31, 2014 and 2013, our accruals for litigation contingencies were $2.4 million and $3.7 million, respectively, and were recorded in our Consolidated Balance Sheets as a component of "Other current liabilities." Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to record additional accruals. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court.

ETP Matter. In connection with a proposed pipeline project, we and Energy Transfer Partners, L.P. ("ETP") signed a non-binding letter of intent in April 2011 that disclaimed any partnership or joint venture related to such project absent executed definitive documents and board approvals of the respective companies. Definitive agreements were never executed and board approval was never obtained for the potential pipeline project. In August 2011, the proposed pipeline project was cancelled due to a lack of customer support.

In September 2011, ETP filed suit against us and a third party in connection with the cancelled project alleging, among other things, that we and ETP had formed a "partnership." The case was tried in the District Court of Dallas County, Texas, 298th Judicial District. While we firmly believe, and argued during our defense, that no agreement was ever executed forming a legal joint venture or partnership between the parties, the jury found that the actions of the two companies, nevertheless, constituted a legal partnership. As a result, the jury found that ETP was wrongfully excluded from a subsequent pipeline project involving a third party, and awarded ETP $319.4 million in actual damages on March 4, 2014. On July 29, 2014, the court entered judgment against us in an aggregate amount of $535.8 million, which includes (i) $319.4 million as the amount of actual damages awarded by the jury, (ii) an additional $150.0 million in disgorgement for the alleged benefit we received due to a breach of fiduciary duties by us against ETP and (iii) prejudgment interest in the amount of $66.4 million. The court also awarded post-judgment interest on such aggregate amount, to accrue at a rate of 5%, compounded annually.

We do not believe that the verdict or the judgment entered against us is supported by the evidence or the law and intend to vigorously oppose the judgment through the appeals process. As of December 31, 2014, we have not recorded a provision for this matter as management believes payment of damages in this case is not probable.

Redelivery Commitments

We store natural gas, crude oil, NGLs and certain petrochemical products owned by third parties under various agreements. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. At December 31, 2014, we had approximately 9.2 trillion British thermal units ("TBtus") of natural gas, 9.3 MMBbls of crude oil, and 28.3 MMBbls of NGL and petrochemical products in our custody that were owned by third parties. We maintain insurance coverage related to such volumes that we believe is consistent with our exposure. See Note 19 for information regarding insurance matters.

Commitments Under Equity Compensation Plans of EPCO

In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 15). See Note 5 for additional information regarding our accounting for equity-based awards.

Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2014. A description of each type of contractual obligation follows:

	Payment or Settlement due by Period
Contractual Obligations	Total		2015		2016		2017		2018		2019		Thereafter
Scheduled maturities of debt obligations	$	21,389.2	$	2,206.5	$	750.0	$	800.0	$	350.0	$	1,500.0	$	15,782.7
Estimated cash interest payments	$	21,303.9	$	1,005.6	$	968.6	$	953.0	$	899.6	$	846.8	$	16,630.3
Operating lease obligations	$	542.7	$	60.5	$	62.0	$	56.4	$	48.9	$	42.3	$	272.6
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	2,139.7	$	637.5	$	539.1	$	295.5	$	295.5	$	195.1	$	177.0
NGLs	$	487.0	$	391.1	$	26.4	$	26.3	$	28.9	$	14.3	$	--
Crude oil	$	2,425.2	$	2,279.1	$	37.4	$	37.3	$	37.3	$	34.1	$	--
Petrochemicals & refined products	$	1,499.3	$	956.7	$	493.1	$	49.5	$	--	$	--	$	--
Other	$	71.8	$	38.1	$	9.2	$	6.9	$	4.2	$	4.2	$	9.2
Underlying major volume commitments:
Natural gas (in TBtus)		879		255		219		128		128		82		67
NGLs (in MMBbls)		30		17		3		4		4		2		--
Crude oil (in MMBbls)		41		38		1		1		1		--		--
Petrochemicals & refined products (in MMBbls)		23		15		7		1		--		--		--
Service payment commitments	$	850.8	$	200.6	$	181.4	$	154.9	$	86.7	$	66.1	$	161.1
Capital expenditure commitments	$	1,299.8	$	1,299.8	$	--	$	--	$	--	$	--	$	--

Scheduled Maturities of Long-Term Debt. We have long-term and short-term payment obligations under debt agreements. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the periods presented. See Note 12 for additional information regarding our consolidated debt obligations.

Estimated Cash Interest Payments. Our estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2014 and the contractually scheduled maturities of such balances. With respect to our variable-rate debt obligation, we applied the weighted-average interest rate paid during 2014 to determine the estimated cash payments. See Note 12 for the weighted-average variable interest rates charged in 2014. Our estimated cash payments for interest are significantly influenced by the long-term maturities of our $1.53 billion in junior subordinated notes. Our estimated cash payments for interest assume that these subordinated notes are not repaid prior to their respective maturity dates. We applied the current fixed interest rate through the respective maturity date for each junior subordinated note to determine the estimated cash payments for interest.

Operating Lease Obligations. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year.

Our significant lease agreements consist of (i) the lease of underground storage caverns for natural gas and NGLs, (ii) leased office space with affiliates of EPCO and (iii) land held pursuant to right-of-way agreements. Currently, our significant lease agreements have terms that range from 5 to 30 years. The agreements for leased office space with affiliates of EPCO and underground NGL storage caverns we lease from a third party include renewal options that could extend these contracts for up to an additional 20 years. The remainder of our significant lease agreements do not provide for additional renewal terms.

Lease expense is charged to operating costs and expenses on a straight-line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. We did not make any significant leasehold improvements during the years ended December 31, 2014, 2013 or 2012.

Consolidated costs and expenses include lease and rental expense amounts of $94.2 million, $87.6 million and $95.1 million during the years ended December 31, 2014, 2013 and 2012, respectively.

Purchase Obligations. We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (i.e., unconditional) on us that specify 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 classify our unconditional purchase obligations into the following categories:

We have long and short-term product purchase obligations for natural gas, NGLs, crude oil, petrochemicals and refined products with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods presented. Our estimated future payment obligations are based on the contractual price in each agreement at December 31, 2014 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. At December 31, 2014, we did not have any significant product purchase commitments with fixed or minimum pricing provisions with remaining terms in excess of one year.

We have long and short-term commitments to pay service providers. Our contractual service payment commitments primarily represent our obligations under firm pipeline transportation contracts. Payment obligations vary by contract, but generally represent a price per unit of volume multiplied by a firm transportation volume commitment.

We have short-term payment obligations relating to our capital spending program, including our share of the capital spending of our unconsolidated affiliates. These commitments represent unconditional payment obligations for services to be rendered or products to be delivered in connection with capital projects.

Other Long-Term Liabilities

The following table summarizes the components of "Other long-term liabilities" as presented on Consolidated Balance Sheets at the dates indicated:

	December 31,
	2014		2013
Noncurrent portion of asset retirement obligations (see Note 8)	$	83.2	$	82.5
Deferred revenues – non-current portion (see Note 2)		73.0		54.6
Liquidity Option Agreement (see Note 10)		119.4		--
Centennial guarantees		7.0		7.8
Other		28.2		27.4
Total	$	310.8	$	172.3

Liquidity Option Agreement

On October 1, 2014, we issued 54,807,352 Enterprise common units to OTA, a U.S. corporation, in connection with Step 1 of the Oiltanking acquisition (see Note 10). In connection with Step 1 of this transaction, we entered into a put option (the "Liquidity Option Agreement") with OTA and Marquard & Bahls ("M&B," a German corporation), the ultimate parent company of OTA, whereby we granted M&B the option to sell to us 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020. At that time, OTA's only significant asset would be the Enterprise common units it received in Step 1 of the Oiltanking acquisition, to the extent that such common units are not sold by M&B prior to the option exercise date pursuant to the related Registration Rights Agreement (see Note 13) or otherwise.

If M&B exercises the put option, any assets or liabilities held by OTA at the time of exercise (e.g., any deferred tax liability), including any Enterprise common units held by OTA, will be indirectly acquired by us upon receipt of OTA's capital stock. The aggregate consideration to be paid by us for OTA's capital stock would equal 100% of the then-current fair market value of the Enterprise common units owned by OTA at the exercise date. The fair market value would be determined by multiplying the number of Enterprise common units owned by OTA at the time of exercise by the volume-weighted sales price per unit of Enterprise common units as reported by the NYSE (or other national securities exchange, as applicable) for the ten consecutive trading days preceding the exercise. The consideration paid may be in the form of newly issued Enterprise common units, cash or any mix thereof, as determined solely by us. Enterprise has the ability to issue the requisite number of common units needed to satisfy any potential obligation under the Liquidity Option Agreement. The Liquidity Option Agreement contains indemnification by M&B for certain specified liabilities of OTA following the closing of any exercise of the Liquidity Option, and certain conditions to closing.

If a defined "Trigger Event" occurs, the Liquidity Option may be exercised earlier within a 135-day period following notice of such event. Pursuant to the Liquidity Option Agreement, a "Trigger Event" means:

§	any transaction, event, circumstance, condition or state of facts by which the Enterprise common units (or any other reference security) cease to be "regularly traded" within the meaning of Section 897 of the U.S. Internal Revenue Code (the "Code") and the Treasury Regulations thereunder;

any transaction, event, circumstance, condition or state of facts by which OTA becomes the owner, for purposes of Section 897 of the Code, of Enterprise common units (or any other reference security) representing more than 5% of all outstanding Enterprise common units (or such reference securities) other than as a result solely of the acquisition of additional Enterprise common units or other reference securities by OTA, M&B or any affiliate after the date of the Liquidity Option Agreement; or

§	any "Enterprise Tax Event" as defined in the agreement, which includes certain events in which OTA would recognize taxable gain on the Enterprise common units owned by OTA.

The aggregate consideration to be paid by us for the Option Securities in connection with an exercise of the option due to a Trigger Event will be solely cash, determined in the same manner as the price otherwise payable upon the exercise of the Liquidity Option in the absence of a Trigger Event.

Based on currently available information, we assigned a provisional fair value of $119.4 million to the Liquidity Option Agreement using an income approach, specifically, a discounted cash flow analysis. This amount represents the present value of estimated federal and state income tax payments that we would make on the taxable income of OTA, a corporation, over a stated period of time following exercise of the option. We expect that OTA's taxable income would, in turn, be based on an allocation of our partnership's taxable income to the common units held by OTA and reflect any tax mitigation strategies we believe could be employed.

Our provisional valuation estimate method is based on significant inputs that are not observable in the market (i.e., Level 3 inputs). Key assumptions in our base case include:

§	OTA remains in existence for 30 years following exercise of option;

§	Annual growth rates of our partnership's earnings before interest, taxes, depreciation and amortization ranging from 3% to 14%;

§	OTA ownership interest in Enterprise common units ranging from 1.9% to 2.8%;

§	OTA assumes approximately $2.2 billion of long-term debt (30-year maturity) from EPO immediately after the option is exercised. The interest rate on this debt approximates 4.9% and is based on a recently completed debt offering with a similar tenure;

§	Forecasted yield on Enterprise common units of 4% to 5.5%;

§	OTA pays an aggregate federal and state income tax rate of 38% on its taxable income; and

§	Discount rate of 7.4% based on our weighted-average cost of capital at October 1, 2014.

Furthermore, our valuation estimate incorporates five probability weighted cases reflecting the likelihood that M&B may elect to divest a portion of the Enterprise common units held by OTA prior to exercise of the option. The following table summarizes these additional assumptions and presents their impact on the determining the provisional valuation estimate:

Scenario	Number of Enterprise Common Units Held at Exercise Date	Discounted Cash Flows		Probability Assigned to Each Scenario	Probability Weighted Cash Flows
	(in millions)
M&B exercises option; OTA owns 100% of units	54.8	$	164.7	50%	$	82.4
M&B exercises option; OTA owns 75% of units	41.1		123.5	20%		24.7
M&B exercises option; OTA owns 50% of units	27.4		82.4	10%		8.2
M&B exercises option; OTA owns 25% of units	13.7		41.2	10%		4.1
M&B does not exercise option	--		--	10%		--
Totals				100%	$	119.4

We believe the information gathered to date provides a reasonable basis for estimating the fair value of the Liquidity Option Agreement, but we are awaiting the availability of certain 2014 federal income tax return calculations that are necessary to finalize our fair value estimate. Thus, our provisional measurement of fair value of $119.4 million is subject to change. We expect to finalize the initial fair value for the Liquidity Option Agreement as soon as practicable but no later than one year from the acquisition date.

The liability recorded for the Liquidity Option Agreement is a component of "Other long-term liabilities" on our Consolidated Balance Sheet at December 31, 2014. Subsequent changes in the fair value of this option (other than those attributable to the finalization of our purchase price allocation as discussed in Note 10) will be recorded in earnings each reporting period until the option expires or is exercised.

Centennial guarantees

At December 31, 2014, Centennial's debt obligations consisted of $75.8 million borrowed under a master shelf loan agreement. Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial's assets and severally guaranteed 50% by us and 50% by our joint venture partner in Centennial. If Centennial were to default on its debt obligations, we and our joint venture partner would each be required to make an approximate $37.9 million payment to Centennial's lenders in connection with the guarantee agreements (based on Centennial's debt principal outstanding at December 31, 2014). We recognized a liability of $5.4 million for our share of the Centennial debt guaranty at December 31, 2014.

In lieu of Centennial procuring insurance to satisfy third party claims arising from a catastrophic event, we and Centennial's other joint venture partner have entered a limited cash call agreement. We are obligated to contribute up to a maximum of $50.0 million in the event of a catastrophic event. At December 31, 2014, we have a recorded liability of $2.4 million representing the estimated fair value of our cash call guaranty. Our cash contributions to Centennial under the agreement may be covered by our other insurance policies depending on the nature of the catastrophic event.

Significant Risks and Uncertainties	12 Months Ended
Significant Risks and Uncertainties	Dec. 31, 2014
Significant Risks and Uncertainties [Abstract]
Significant Risks and Uncertainties	Note 19. Significant Risks and Uncertainties Nature of Operations in Midstream Energy Industry Our operations are within the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, refined products and certain petrochemicals. We also market natural gas, NGLs, crude oil and other hydrocarbon products. A reduction in demand for our processing, transportation or other midstream services by domestic producers, whether because of low prices for crude oil, NGLs, natural gas or other reasons that negatively impact upstream production activity, could adversely affect our financial position, results of operations and cash flows. In addition, a reduction in demand for natural gas, NGLs, crude oil, refined products, petrochemicals and other hydrocarbon products by the petrochemical, refining or heating industries, whether because of general economic conditions; reduced demand by customers; increased competition from other products due to pricing differences; adverse weather conditions; government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline; or for other reasons, could adversely affect our financial position, results of operations and cash flows. Credit Risk Due to Industry Concentrations A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions. We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults. Our largest non-affiliated customer for 2014 was Shell, which accounted for 8.5% of our consolidated revenues for this period. Counterparty Risk with Respect to Derivative Instruments In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty's financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral for such transactions nor do we currently anticipate nonperformance by our counterparties. Insurance Matters We participate as a named insured in EPCO's insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows. In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of our common units. Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to a fire). Some of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Consolidated Balance Sheets and presented as "Capital expenditures" on our Statements of Consolidated Cash Flows. Currently, EPCO's deductibles for property damage claims range from $5.0 million to $60.0 million depending on the nature of the loss (windstorm or non-windstorm) and the assets involved (onshore or offshore assets). We continue to maintain business interruption coverage for our onshore and offshore assets, except for those situations involving windstorm-related downtime for our offshore assets. We received $95.0 million, $15.0 million and $30.0 million of nonrefundable insurance proceeds during the years ended December 31, 2014, 2013 and 2012, respectively, attributable to property damage claims we filed in connection with a February 2011 NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility. Operating income for the years ended December 31, 2014, 2013 and 2012 includes $95.0 million, $15.0 million and $30.0 million of gains, respectively, related to these insurance recoveries. The amounts we received during the first quarter of 2014 represent the final payments on this property damage claim. Due to the high cost of windstorm insurance coverage for our offshore Gulf of Mexico assets, we elected to self-insure these assets during the annual policy period extending from June 2013 to June 2014. We continue to self-insure these assets for the current annual policy period, which extends from June 2014 to June 2015. Although EPCO's current insurance program does not provide any windstorm coverage for our offshore assets, producers affiliated with our Independence Hub and Marco Polo platforms continue to provide certain levels of physical damage windstorm coverage for each of these offshore assets.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Note 20. Supplemental Cash Flow Information

The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Decrease (increase) in:
Accounts receivable – trade	$	1,685.4		$	(1,136.2	)	$	161.5
Accounts receivable – related parties		3.8			(3.6	)		35.3
Inventories		(105.6	)		38.6			(227.8	)
Prepaid and other current assets		(74.6	)		(6.3	)		(12.6	)
Other assets		18.7			2.4			(39.6	)
Increase (decrease) in:
Accounts payable – trade		(141.0	)		(10.1	)		34.1
Accounts payable – related parties		(31.6	)		23.6			(84.3	)
Accrued product payables		(1,647.8	)		1,043.8			(422.5	)
Accrued interest		31.3			3.5			12.7
Other current liabilities		141.3			(35.1	)		(14.4	)
Other liabilities		11.9			(18.2	)		(24.9	)
Net effect of changes in operating accounts	$	(108.2	)	$	(97.6	)	$	(582.5	)

Cash payments for interest, net of $77.9, $133.0 and $116.8 capitalized in 2014, 2013 and 2012, respectively	$	832.1		$	781.5		$	757.3

Cash payments for federal and state income taxes	$	16.1		$	35.0		$	44.8

We incurred liabilities for construction in progress that had not been paid at December 31, 2014, 2013 and 2012 of $372.8 million, $205.3 million and $221.7 million, respectively. Such amounts are not included under the caption "Capital expenditures" on the Statements of Consolidated Cash Flows.

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. These cash receipts are presented as "Contributions in aid of construction costs" within the investing activities section of our Statements of Consolidated Cash Flows.

The following table presents our cash proceeds from asset sales and insurance recoveries for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Sale of Energy Transfer Equity common units (see Note 9)	$	--	$	--	$	1,095.3
Sale of Stratton Ridge-to-Mont Belvieu segment of Seminole Pipeline (see Note 8)		--		86.9		--
Sales of pipeline line fill		27.5		65.0		--
Sale of lubrication oil and specialty chemical distribution assets		--		35.3		--
Sale of chemical trucking assets		--		29.5		--
Insurance recoveries attributable to West Storage claims (see Note 19)		95.0		15.0		30.0
Other cash proceeds		22.8		48.9		73.5
Total	$	145.3	$	280.6	$	1,198.8

The following table presents net gains (losses) attributable to asset sales and insurance recoveries for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Sale of Energy Transfer Equity common units (see Note 9)	$	--	$	--	$	68.8
Sale of Stratton Ridge-to-Mont Belvieu segment of Seminole Pipeline (see Note 8)		--		52.5		--
Net gains (losses) attributable to other asset sales		7.1		15.8		(12.4	)
Gains attributable to insurance recoveries (see Note 19)		95.0		15.0		30.0
Total	$	102.1	$	83.3	$	86.4

See Note 10 for information regarding non-cash consideration we issued in connection with Step 1 of the Oiltanking acquisition.

See Note 13 for information regarding cash contributions and distributions attributable to noncontrolling interests as seen on the Statements of Consolidated Cash Flows.

Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information (Unaudited) [Abstract]

Quarterly Financial Information (Unaudited)

Note 21. Quarterly Financial Information (Unaudited)

The following table presents selected quarterly financial data for the periods indicated:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
For the Year Ended December 31, 2014:
Revenues	$	12,909.9	$	12,520.8	$	12,330.2	$	10,190.3
Operating income		1,032.7		884.3		937.7		921.0
Net income		806.7		646.5		699.2		681.1
Net income attributable to limited partners		798.8		637.7		691.1		659.8

Earnings per unit:
Basic	$	0.44	$	0.35	$	0.38	$	0.35
Diluted	$	0.43	$	0.34	$	0.37	$	0.34

For the Year Ended December 31, 2013:
Revenues	$	11,383.1	$	11,149.3	$	12,093.3	$	13,101.3
Operating income		957.7		774.2		819.9		915.5
Net income		755.3		553.3		592.8		705.7
Net income attributable to limited partners		753.5		552.5		592.0		698.9

Earnings per unit:
Basic	$	0.43	$	0.31	$	0.33	$	0.38
Diluted	$	0.41	$	0.30	$	0.32	$	0.37

The sum of our quarterly earnings per unit amounts may not equal our full year amounts due to slight rounding differences.

Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2014

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

Note 22. Condensed Consolidating Financial Information

EPO conducts all of our business. Currently, we have no independent operations and no material assets outside those of EPO.

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 the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full and unconditional repayment of that obligation. EPO's consolidated subsidiaries have no significant restrictions on their ability to pay distributions or make loans to Enterprise Products Partners L.P. See Note 12 for additional information regarding our consolidated debt obligations.

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2014

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	18.7	$	70.4	$	(14.7	)	$	74.4	$	--	$	--		$	74.4
Accounts receivable – trade, net		1,128.5		2,698.2		(3.7	)		3,823.0		--		--			3,823.0
Accounts receivable – related parties		158.8		1,114.6		(1,266.6	)		6.8		--		(4.0	)		2.8
Inventories		831.8		182.8		(0.4	)		1,014.2		--		--			1,014.2
Prepaid and other current assets		537.7		346.3		(308.5	)		575.5		--		0.8			576.3
Total current assets		2,675.5		4,412.3		(1,593.9	)		5,493.9		--		(3.2	)		5,490.7
Property, plant and equipment, net		2,871.7		26,912.0		97.9			29,881.6		--		--			29,881.6
Investments in unconsolidated affiliates		36,937.5		3,556.4		(37,451.9	)		3,042.0		18,187.2		(18,187.2	)		3,042.0
Intangible assets, net		2,527.3		1,292.4		482.4			4,302.1		--		--			4,302.1
Goodwill		1,956.1		1,621.1		622.7			4,199.9		--		--			4,199.9
Other assets		139.3		45.8		(0.7	)		184.4		--		--			184.4
Total assets	$	47,107.4	$	37,840.0	$	(37,843.5	)	$	47,103.9	$	18,187.2	$	(18,190.4	)	$	47,100.7

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	2,206.4	$	--	$	--		$	2,206.4	$	--	$	--		$	2,206.4
Accounts payable – trade		216.6		571.4		(14.8	)		773.2		0.6		--			773.8
Accounts payable – related parties		1,226.5		173.3		(1,280.9	)		118.9		4.0		(4.0	)		118.9
Accrued product payables		1,570.0		2,287.9		(4.6	)		3,853.3		--		--			3,853.3
Accrued interest		335.4		0.7		(0.6	)		335.5		--		--			335.5
Other current liabilities		130.8		763.7		(308.7	)		585.8		--		--			585.8
Total current liabilities		5,685.7		3,797.0		(1,609.6	)		7,873.1		4.6		(4.0	)		7,873.7
Long-term debt		19,142.5		14.9		--			19,157.4		--		--			19,157.4
Deferred tax liabilities		4.9		58.5		(0.9	)		62.5		--		4.1			66.6
Other long-term liabilities		10.9		180.8		(0.3	)		191.4		119.4		--			310.8
Commitments and contingencies		--
Equity:
Partners' and other owners' equity		22,263.4		33,720.6		(37,820.6	)		18,163.4		18,063.2		(18,163.4	)		18,063.2
Noncontrolling interests		--		68.2		1,587.9			1,656.1		--		(27.1	)		1,629.0
Total equity		22,263.4		33,788.8		(36,232.7	)		19,819.5		18,063.2		(18,190.5	)		19,692.2
Total liabilities and equity	$	47,107.4	$	37,840.0	$	(37,843.5	)	$	47,103.9	$	18,187.2	$	(18,190.4	)	$	47,100.7

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2013

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	93.9	$	49.5	$	(20.9	)	$	122.5	$	--	$	--		$	122.5
Accounts receivable – trade, net		1,986.8		3,491.1		(2.4	)		5,475.5		--		--			5,475.5
Accounts receivable – related parties		384.7		1,348.1		(1,726.0	)		6.8		0.2		(0.2	)		6.8
Inventories		948.5		145.4		(0.8	)		1,093.1		--		--			1,093.1
Prepaid and other current assets		140.9		191.4		(6.8	)		325.5		--		--			325.5
Total current assets		3,554.8		5,225.5		(1,756.9	)		7,023.4		0.2		(0.2	)		7,023.4
Property, plant and equipment, net		1,945.0		24,999.7		1.9			26,946.6		--		--			26,946.6
Investments in unconsolidated affiliates		30,819.9		2,921.2		(31,304.0	)		2,437.1		15,214.5		(15,214.5	)		2,437.1
Intangible assets, net		76.9		1,385.3		--			1,462.2		--		--			1,462.2
Goodwill		458.9		1,621.1		--			2,080.0		--		--			2,080.0
Other assets		123.5		67.2		(1.4	)		189.3		0.1		--			189.4
Total assets	$	36,979.0	$	36,220.0	$	(33,060.4	)	$	40,138.6	$	15,214.8	$	(15,214.7	)	$	40,138.7

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,125.0	$	--	$	--		$	1,125.0	$	--	$	--		$	1,125.0
Accounts payable – trade		103.0		641.6		(20.9	)		723.7		--		--			723.7
Accounts payable – related parties		1,541.8		333.8		(1,724.9	)		150.7		--		(0.2	)		150.5
Accrued product payables		2,388.6		3,224.5		(4.4	)		5,608.7		--		--			5,608.7
Accrued interest		304.2		0.1		--			304.3		--		--			304.3
Other current liabilities		92.3		242.4		(6.7	)		328.0		--		(1.5	)		326.5
Total current liabilities		5,554.9		4,442.4		(1,756.9	)		8,240.4		--		(1.7	)		8,238.7
Long-term debt		16,211.6		14.9		--			16,226.5		--		--			16,226.5
Deferred tax liabilities		4.3		55.0		(1.4	)		57.9		--		2.9			60.8
Other long-term liabilities		11.8		160.5		--			172.3		--		--			172.3
Commitments and contingencies
Equity:
Partners' and other owners' equity		15,196.4		31,475.9		(31,482.4	)		15,189.9		15,214.8		(15,189.9	)		15,214.8
Noncontrolling interests		--		71.3		180.3			251.6		--		(26.0	)		225.6
Total equity		15,196.4		31,547.2		(31,302.1	)		15,441.5		15,214.8		(15,215.9	)		15,440.4
Total liabilities and equity	$	36,979.0	$	36,220.0	$	(33,060.4	)	$	40,138.6	$	15,214.8	$	(15,214.7	)	$	40,138.7

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2014

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	32,468.5		$	32,488.2		$	(17,005.5	)	$	47,951.2		$	--	$	--		$	47,951.2
Costs and expenses:
Operating costs and expenses		31,579.2			29,647.6			(17,006.3	)		44,220.5			--		--			44,220.5
General and administrative costs		39.1			173.2			--			212.3			2.2		--			214.5
Total costs and expenses		31,618.3			29,820.8			(17,006.3	)		44,432.8			2.2		--			44,435.0
Equity in income of unconsolidated affiliates		2,865.2			354.3			(2,960.0	)		259.5			2,789.6		(2,789.6	)		259.5
Operating income		3,715.4			3,021.7			(2,959.2	)		3,777.9			2,787.4		(2,789.6	)		3,775.7
Other income (expense):
Interest expense		(921.3	)		(2.5	)		2.8			(921.0	)		--		--			(921.0	)
Other, net		3.4			1.3			(2.8	)		1.9			--		--			1.9
Total other expense, net		(917.9	)		(1.2	)		--			(919.1	)		--		--			(919.1	)
Income before income taxes		2,797.5			3,020.5			(2,959.2	)		2,858.8			2,787.4		(2,789.6	)		2,856.6
Provision for income taxes		(11.5	)		(9.8	)		0.2			(21.1	)		--		(2.0	)		(23.1	)
Net income		2,786.0			3,010.7			(2,959.0	)		2,837.7			2,787.4		(2,791.6	)		2,833.5
Net loss (income) attributable to noncontrolling interests		--			0.4			(51.5	)		(51.1	)		--		5.0			(46.1	)
Net income attributable to entity	$	2,786.0		$	3,011.1		$	(3,010.5	)	$	2,786.6		$	2,787.4	$	(2,786.6	)	$	2,787.4

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2013

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	30,007.4		$	31,641.3		$	(13,921.7	)	$	47,727.0		$	--	$	--		$	47,727.0
Costs and expenses:
Operating costs and expenses		29,176.7			28,983.7			(13,921.7	)		44,238.7			--		--			44,238.7
General and administrative costs		29.1			157.0			--			186.1			2.2		--			188.3
Total costs and expenses		29,205.8			29,140.7			(13,921.7	)		44,424.8			2.2		--			44,427.0
Equity in income of unconsolidated affiliates		2,609.0			204.8			(2,646.5	)		167.3			2,599.1		(2,599.1	)		167.3
Operating income		3,410.6			2,705.4			(2,646.5	)		3,469.5			2,596.9		(2,599.1	)		3,467.3
Other income (expense):
Interest expense		(800.8	)		(1.7	)		--			(802.5	)		--		--			(802.5	)
Other, net		0.3			(0.5	)		--			(0.2	)		--		--			(0.2	)
Total other expense, net		(800.5	)		(2.2	)		--			(802.7	)		--		--			(802.7	)
Income before income taxes		2,610.1			2,703.2			(2,646.5	)		2,666.8			2,596.9		(2,599.1	)		2,664.6
Provision for income taxes		(13.9	)		(42.6	)		--			(56.5	)		--		(1.0	)		(57.5	)
Net income		2,596.2			2,660.6			(2,646.5	)		2,610.3			2,596.9		(2,600.1	)		2,607.1
Net loss (income) attributable to noncontrolling interests		--			(1.2	)		(12.9	)		(14.1	)		--		3.9			(10.2	)
Net income attributable to entity	$	2,596.2		$	2,659.4		$	(2,659.4	)	$	2,596.2		$	2,596.9	$	(2,596.2	)	$	2,596.9

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	29,654.7		$	28,221.5		$	(15,293.1	)	$	42,583.1		$	--	$	--		$	42,583.1
Costs and expenses:
Operating costs and expenses		28,839.1			25,821.8			(15,293.0	)		39,367.9			--		--			39,367.9
General and administrative costs		26.1			142.7			--			168.8			1.5		--			170.3
Total costs and expenses		28,865.2			25,964.5			(15,293.0	)		39,536.7			1.5		--			39,538.2
Equity in income of unconsolidated affiliates		2,381.8			80.7			(2,398.2	)		64.3			2,421.4		(2,421.4	)		64.3
Operating income		3,171.3			2,337.7			(2,398.3	)		3,110.7			2,419.9		(2,421.4	)		3,109.2
Other income (expense):
Interest expense		(767.1	)		(4.7	)		--			(771.8	)		--		--			(771.8	)
Other, net		0.1			73.3			--			73.4			--		--			73.4
Total other expense, net		(767.0	)		68.6			--			(698.4	)		--		--			(698.4	)
Income before income taxes		2,404.3			2,406.3			(2,398.3	)		2,412.3			2,419.9		(2,421.4	)		2,410.8
Provision for income taxes		15.7			2.4			--			18.1			--		(0.9	)		17.2
Net income		2,420.0			2,408.7			(2,398.3	)		2,430.4			2,419.9		(2,422.3	)		2,428.0
Net loss (income) attributable to noncontrolling interests		--			(5.1	)		(5.3	)		(10.4	)		--		2.3			(8.1	)
Net income attributable to entity	$	2,420.0		$	2,403.6		$	(2,403.6	)	$	2,420.0		$	2,419.9	$	(2,420.0	)	$	2,419.9

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2014

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments				Consolidated EPO and Subsidiaries				Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments				Consolidated Total
Comprehensive income		$	2,856.4		$	3,057.6		$	(2,958.9	)		$	2,955.1			$	2,904.8		$	(2,909.0	)		$	2,950.9
Comprehensive loss (income) attributable to noncontrolling interests			--			0.4			(51.5	)			(51.1	)			--			5.0				(46.1	)
Comprehensive income attributable to entity		$	2,856.4		$	3,058.0		$	(3,010.4	)		$	2,904.0			$	2,904.8		$	(2,904.0	) )		$	2,904.8

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2013

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)				EPO and Subsidiaries Eliminations and Adjustments				Consolidated EPO and Subsidiaries				Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments				Consolidated Total
Comprehensive income		$	2,616.5		$	2,651.6			$	(2,646.5	)		$	2,621.6			$	2,608.3		$	(2,611.4	)		$	2,618.5
Comprehensive income attributable to noncontrolling interests			--			(1.2	)			(12.9	)			(14.1	)			--			3.9				(10.2	)
Comprehensive income attributable to entity		$	2,616.5		$	2,650.4			$	(2,659.4	)		$	2,607.5			$	2,608.3		$	(2,607.5	)		$	2,608.3

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)				EPO and Subsidiaries Eliminations and Adjustments				Consolidated EPO and Subsidiaries				Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments				Consolidated Total
Comprehensive income		$	2,375.8		$	2,433.9			$	(2,398.3	)		$	2,411.4			$	2,400.9		$	(2,403.3	)		$	2,409.0
Comprehensive income attributable to noncontrolling interests			--			(5.1	)			(5.3	)			(10.4	)			--			2.3				(8.1	)
Comprehensive income attributable to entity		$	2,375.8		$	2,428.8			$	(2,403.6	)		$	2,401.0			$	2,400.9		$	(2,401.0	) )		$	2,400.9

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2014

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,786.0		$	3,010.7		$	(2,959.0	)	$	2,837.7		$	2,787.4		$	(2,791.6	)	$	2,833.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		153.0			1,208.0			(0.5	)		1,360.5			--			--			1,360.5
Equity in income of unconsolidated affiliates		(2,865.2	)		(354.3	)		2,960.0			(259.5	)		(2,789.6	)		2,789.6			(259.5	)
Distributions received from unconsolidated affiliates		4,539.9			327.1			(4,491.9	)		375.1			2,702.9			(2,702.9	)		375.1
Net effect of changes in operating accounts and other operating activities		(627.0	)		479.4			5.7			(141.9	)		(7.5	)		2.0			(147.4	)
Net cash flows provided by operating activities		3,986.7			4,670.9			(4,485.7	)		4,171.9			2,693.2			(2,702.9	)		4,162.2
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(647.9	)		(2,216.1	)		--			(2,864.0	)		--			--			(2,864.0	)
Cash used for business combinations, net of cash received		(2,437.5	)		20.7			--			(2,416.8	)		--			--			(2,416.8	)
Proceeds from asset sales and insurance recoveries		4.3			141.0			--			145.3			--			--			145.3
Other investing activities		(2,603.4	)		(660.0	)		2,601.0			(662.4	)		(384.6	)		384.6			(662.4	)
Cash used in investing activities		(5,684.5	)		(2,714.4	)		2,601.0			(5,797.9	)		(384.6	)		384.6			(5,797.9	)
Financing activities:
Borrowings under debt agreements		18,361.1			--			--			18,361.1			--			--			18,361.1
Repayments of debt		(14,341.1	)		--			--			(14,341.1	)		--			--			(14,341.1	)
Cash distributions paid to partners		(2,702.9	)		(4,537.8	)		4,537.8			(2,702.9	)		(2,638.1	)		2,702.9			(2,638.1	)
Cash payments made in connection with DERs		--			--			--			--			(3.7	)		--			(3.7	)
Cash distributions paid to noncontrolling interests		--			(2.7	)		(45.9	)		(48.6	)		--			--			(48.6	)
Cash contributions from noncontrolling interests		--			--			4.0			4.0			--			--			4.0
Net cash proceeds from issuance of common units		--			--			--			--			388.8			--			388.8
Cash contributions from owners		384.6			2,604.9			(2,604.9	)		384.6			--			(384.6	)		--
Other financing activities		(13.6	)		--			--			(13.6	)		(55.6	)		--			(69.2	)
Cash provided by (used in) financing activities		1,688.1			(1,935.6	)		1,891.0			1,643.5			(2,308.6	)		2,318.3			1,653.2
Net change in cash and cash equivalents		(9.7	)		20.9			6.3			17.5			--			--			17.5
Cash and cash equivalents, January 1		28.4			49.5			(21.0	)		56.9			--			--			56.9
Cash and cash equivalents, December 31	$	18.7		$	70.4		$	(14.7	)	$	74.4		$	--		$	--		$	74.4

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2013

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,596.2		$	2,660.6		$	(2,646.5	)	$	2,610.3		$	2,596.9		$	(2,600.1	)	$	2,607.1
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		143.5			1,072.8			1.3			1,217.6			--			--			1,217.6
Equity in income of unconsolidated affiliates		(2,609.0	)		(204.8	)		2,646.5			(167.3	)		(2,599.1	)		2,599.1			(167.3	)
Distributions received from unconsolidated affiliates		4,523.2			233.7			(4,505.3	)		251.6			2,454.4			(2,454.4	)		251.6
Net effect of changes in operating accounts and other operating activities		(1,351.0	)		1,323.4			(10.1	)		(37.7	)		(7.8	)		2.0			(43.5	)
Net cash flows provided by operating activities		3,302.9			5,085.7			(4,514.1	)		3,874.5			2,444.4			(2,453.4	)		3,865.5
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(517.8	)		(2,864.4	)		--			(3,382.2	)		--			--			(3,382.2	)
Proceeds from asset sales and insurance recoveries		59.6			221.0			--			280.6			--			--			280.6
Other investing activities		(3,163.6	)		(769.5	)		2,777.2			(1,155.9	)		(1,791.1	)		1,791.1			(1,155.9	)
Cash used in investing activities		(3,621.8	)		(3,412.9	)		2,777.2			(4,257.5	)		(1,791.1	)		1,791.1			(4,257.5	)
Financing activities:
Borrowings under debt agreements		13,852.8			--			--			13,852.8			--			--			13,852.8
Repayments of debt		(12,650.8	)		(29.8	)		--			(12,680.6	)		--			--			(12,680.6	)
Cash distributions paid to partners		(2,453.4	)		(4,514.1	)		4,514.1			(2,453.4	)		(2,400.4	)		2,453.5			(2,400.3	)
Cash distributions paid to noncontrolling interests		--			--			(8.9	)		(8.9	)		--			--			(8.9	)
Cash contributions from noncontrolling interests		--			--			115.4			115.4			--			--			115.4
Net cash proceeds from issuance of common units		--			--			--			--			1,792.0			--			1,792.0
Cash contributions from owners		1,791.2			2,892.6			(2,892.6	)		1,791.2			--			(1,791.2	)		--
Other financing activities		(192.5	)		--			--			(192.5	)		(45.1	)		--			(237.6	)
Cash provided by (used in) financing activities		347.3			(1,651.3	)		1,728.0			424.0			(653.5	)		662.3			432.8
Net change in cash and cash equivalents		28.4			21.5			(8.9	)		41.0			(0.2	)		--			40.8
Cash and cash equivalents, January 1		--			28.0			(12.1	)		15.9			0.2			--			16.1
Cash and cash equivalents, December 31	$	28.4		$	49.5		$	(21.0	)	$	56.9		$	--		$	--		$	56.9

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,420.0		$	2,408.7		$	(2,398.3	)	$	2,430.4		$	2,419.9		$	(2,422.3	)	$	2,428.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		118.0			986.9			--			1,104.9			--			--			1,104.9
Equity in income of unconsolidated affiliates		(2,381.8	)		(80.7	)		2,398.2			(64.3	)		(2,421.4	)		2,421.4			(64.3	)
Distributions received from unconsolidated affiliates		3,918.9			106.6			(3,908.8	)		116.7			2,209.3			(2,209.3	)		116.7
Net effect of changes in operating accounts and other operating activities		(2,174.9	)		1,485.3			(0.8	)		(690.4	)		(4.9	)		0.9			(694.4	)
Net cash flows provided by operating activities		1,900.2			4,906.8			(3,909.7	)		2,897.3			2,202.9			(2,209.3	)		2,890.9
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(219.5	)		(3,379.0	)		--			(3,598.5	)		--			--			(3,598.5	)
Proceeds from asset sales and insurance recoveries		1,137.2			61.6			--			1,198.8			--			--			1,198.8
Other investing activities		(2,961.4	)		(432.3	)		2,774.6			(619.1	)		(816.2	)		816.2			(619.1	)
Cash used in investing activities		(2,043.7	)		(3,749.7	)		2,774.6			(3,018.8	)		(816.2	)		816.2			(3,018.8	)
Financing activities:
Borrowings under debt agreements		8,363.1			--			--			8,363.1			--			--			8,363.1
Repayments of debt		(6,666.9	)		(9.5	)		--			(6,676.4	)		--			--			(6,676.4	)
Cash distributions paid to partners		(2,209.3	)		(3,922.1	)		3,922.1			(2,209.3	)		(2,178.6	)		2,209.3			(2,178.6	)
Cash distributions paid to noncontrolling interests		--			--			(13.3	)		(13.3	)		--			--			(13.3	)
Cash contributions from noncontrolling interests		--			--			6.6			6.6			--			--			6.6
Net cash proceeds from issuance of common units		--			--			--			--			816.8			--			816.8
Cash contributions from owners		816.2			2,781.2			(2,781.2	)		816.2			--			(816.2	)		--
Other financing activities		(169.3	)		--			--			(169.3	)		(24.7	)		--			(194.0	)
Cash provided by (used in) financing activities		133.8			(1,150.4	)		1,134.2			117.6			(1,386.5	)		1,393.1			124.2
Net change in cash and cash equivalents		(9.7	)		6.7			(0.9	)		(3.9	)		0.2			--			(3.7	)
Cash and cash equivalents, January 1		9.7			21.3			(11.2	)		19.8			--			--			19.8
Cash and cash equivalents, December 31	$	--		$	28.0		$	(12.1	)	$	15.9		$	0.2		$	--		$	16.1

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies [Abstract]

Allowance for Doubtful Accounts

The following table presents our allowance for doubtful accounts activity for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Balance at beginning of period	$	7.5		$	13.2		$	13.4
Charged to costs and expenses		8.4			2.1			0.3
Deductions (1)		(2.0	)		(7.8	)		(0.5	)
Balance at end of period	$	13.9		$	7.5		$	13.2

(1) The 2013 deduction is primarily due to the write-off of certain amounts attributable to companies in bankruptcy and amounts we believe are no longer collectible.

See "Credit Risk Due to Industry Concentrations" in Note 19 for additional information.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.

Consolidation Policy

Contingencies

Current Assets and Current Liabilities

We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and liabilities, respectively.

Derivative Instruments

Earnings Per Unit

Environmental Costs

The following table presents the activity of our environmental reserves for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Balance at beginning of period	$	9.9		$	13.7		$	12.3
Charged to costs and expenses		11.9			3.9			13.9
Acquisition-related additions and other		2.5			0.7			5.2
Deductions		(8.7	)		(8.4	)		(17.7	)
Balance at end of period	$	15.6		$	9.9		$	13.7

At December 31, 2014 and 2013, $8.1 million and $6.0 million, respectively, of our environmental reserves were classified as current liabilities.

Equity-based Awards

See Note 5 for information regarding our accounting for equity-based awards.

Estimates

Impairment Testing for Goodwill

Impairment Testing for Long-Lived Assets

Impairment Testing for Unconsolidated Affiliates

Income Taxes

Other Non-Operating Income

The following table presents the components of "Other, net" as presented on our Statements of Consolidated Operations for the periods indicated:

	For the Year Ended December 31,
	2014		2013			2012
Gain on sales of available-for-sale securities of Energy Transfer Equity (1)	$	--	$	--		$	68.8
Other		0.6		(1.1	)		3.8
Total	$	0.6	$	(1.1	)	$	72.6

(1) See Note 9 for information regarding the liquidation of our investment in limited partnership units of Energy Transfer Equity.

Property, Plant and Equipment

Restricted Cash

Revenue Recognition

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Summary of Significant Accounting Policies [Abstract]

Allowance for Doubtful Accounts Activity

The following table presents our allowance for doubtful accounts activity for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Balance at beginning of period	$	7.5		$	13.2		$	13.4
Charged to costs and expenses		8.4			2.1			0.3
Deductions (1)		(2.0	)		(7.8	)		(0.5	)
Balance at end of period	$	13.9		$	7.5		$	13.2

(1) The 2013 deduction is primarily due to the write-off of certain amounts attributable to companies in bankruptcy and amounts we believe are no longer collectible.

Environmental Reserves Activity

The following table presents the activity of our environmental reserves for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Balance at beginning of period	$	9.9		$	13.7		$	12.3
Charged to costs and expenses		11.9			3.9			13.9
Acquisition-related additions and other		2.5			0.7			5.2
Deductions		(8.7	)		(8.4	)		(17.7	)
Balance at end of period	$	15.6		$	9.9		$	13.7

Components of Other net

The following table presents the components of "Other, net" as presented on our Statements of Consolidated Operations for the periods indicated:

	For the Year Ended December 31,
	2014		2013			2012
Gain on sales of available-for-sale securities of Energy Transfer Equity (1)	$	--	$	--		$	68.8
Other		0.6		(1.1	)		3.8
Total	$	0.6	$	(1.1	)	$	72.6

(1) See Note 9 for information regarding the liquidation of our investment in limited partnership units of Energy Transfer Equity.

Equity-based Awards (Tables)

12 Months Ended

Dec. 31, 2014

Equity-based Awards [Abstract]

Equity-based Award Expense

	For the Year Ended December 31,
	2014		2013		2012
Equity-classified awards:
Restricted common unit awards	$	42.1	$	71.5	$	57.0
Unit option awards		--		0.8		1.3
Phantom unit awards		45.1		--		--
Liability-classified awards		0.3		0.5		1.7
Total	$	87.5	$	72.8	$	60.0

Restricted Common Unit Awards

The following table presents information regarding restricted common unit awards for the periods indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at December 31, 2011		7,736,432		$	17.11
Granted (2)		3,177,476		$	25.98
Vested		(2,633,206	)	$	17.40
Forfeited		(493,730	)	$	20.21
Restricted common units at December 31, 2012		7,786,972		$	20.43
Granted (3)		3,549,052		$	28.61
Vested		(3,770,696	)	$	17.48
Forfeited		(344,114	)	$	23.82
Restricted common units at December 31, 2013		7,221,214		$	25.83
Vested		(2,634,074	)	$	23.94
Forfeited		(357,350	)	$	26.38
Restricted common units at December 31, 2014		4,229,790		$	26.96

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued during 2012 was $82.5 million based on a grant date market price of our common units ranging from $25.96 to $26.77 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards. (3) The aggregate grant date fair value of restricted common unit awards issued during 2013 was $101.5 million based on a grant date market price of our common units ranging from $28.56 to $31.74 per unit. An estimated annual forfeiture rate of 3.9% was applied to these awards.

Cash Distributions and Total Intrinsic Value of Restricted Common Units

The following table presents supplemental information regarding restricted common unit awards for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Cash distributions paid to restricted common unitholders	$	7.3	$	10.6	$	10.5
Total intrinsic value of restricted common unit awards that vested during period	$	87.1	$	109.9	$	67.0

Unit Option Activity

The following table presents unit option award activity for the periods indicated:

	Number of Units			Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Unit option awards at December 31, 2011		7,506,840		$	14.04
Exercised		(1,484,560	)	$	15.39
Forfeited		(500,000	)	$	13.73
Unit option awards at December 31, 2012		5,522,280		$	13.71
Exercised		(1,472,280	)	$	14.98
Unit option awards at December 31, 2013 (2,3)		4,050,000		$	13.24
Exercised		(2,720,000	)	$	11.83
Forfeited		(60,000	)	$	16.14
Unit option awards at December 31, 2014 (2,3)		1,270,000		$	16.14		1.0	$	25.4

(1) Aggregate intrinsic value reflects fully vested unit option awards at the date indicated. (2) At December 31, 2014 and 2013, we were committed to issue 1,270,000 and 4,050,000, respectively, of our common units if all outstanding unit option awards were exercised. All of the unit option awards outstanding at December 31, 2014 vested during 2014 and became exercisable beginning in February 2015. (3) None of the unit option awards outstanding at December 31, 2014, 2013 and 2012 were exercisable as of such dates, respectively.

Supplemental Information Regarding Unit Options

The following table presents supplemental information regarding unit option awards during the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Total intrinsic value of unit option awards exercised during period	$	57.5	$	19.8	$	14.6
Cash received from EPCO in connection with the exercise of unit option awards	$	33.4	$	11.5	$	10.2
Unit option award-related cash reimbursements to EPCO	$	57.5	$	19.8	$	14.0

Phantom Unit Awards

The following table presents phantom unit award activity for the period indicated:

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Phantom unit awards at December 31, 2013		--		$	--
Granted (2)		3,530,710		$	33.12
Vested		(38,200	)	$	33.04
Forfeited		(150,120	)	$	33.12
Phantom unit awards at December 31, 2014		3,342,390		$	33.13

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of phantom unit awards issued during 2014 was $117.0 million based on a grant date market price of our common units ranging from $33.04 to $37.59 per unit. An estimated annual forfeiture rate of 3.4% was applied to these awards.

Cash Distributions and Total Intrinsic Value of Phantom Unit Awards

The following table presents supplemental information regarding our phantom unit awards for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Cash payments made in connection with DERs	$	3.7	$	--	$	--
Total intrinsic value of phantom unit awards that vested during period	$	1.4	$	--	$	--

Derivative Instruments, Hedging Activities and Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract]

Hedging Instruments Under the FASB's Derivative and Hedging Guidance

	Volume (1)				Accounting
Derivative Purpose	Current (2)		Long-Term (2)		Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted sales of NGLs (MMBbls) (3)		0.9		n/a	Cash flow hedge
Natural gas marketing:
Forecasted sales of natural gas (Bcf)		1.0		n/a	Cash flow hedge
Natural gas storage inventory management activities (Bcf)		8.6		n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)		9.9		n/a	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)		10.2		n/a	Cash flow hedge
Refined products marketing:
Forecasted purchases of refined products (MMBbls)		1.2		n/a	Cash flow hedge
Forecasted sales of refined products (MMBbls)		1.8		n/a	Cash flow hedge
Refined products inventory management activities (MMBbls)		0.2		n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)		5.8		n/a	Cash flow hedge
Forecasted sales of crude oil (MMBbls)		6.9		n/a	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (4,5)		81.4		11.8	Mark-to-market
Crude oil risk management activities (MMBbls) (5)		4.2		n/a	Mark-to-market

(1)

(2)

(3)

Forecasted sales of NGL volumes under natural gas processing exclude 0.1 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.

(4)

Current volumes include 35.2 Bcf of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences.

(5)

Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Assets and Liabilities Balance Sheet

The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:

	Asset Derivatives						Liability Derivatives
	December 31, 2014			December 31, 2013			December 31, 2014			December 31, 2013
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	20.2	Other current liabilities	$	--	Other current liabilities	$	--
Interest rate derivatives	Other assets		--	Other assets		12.4	Other liabilities		--	Other liabilities		--
Total interest rate derivatives			--			32.6			--			--
Commodity derivatives	Other current assets		217.9	Other current assets		30.9	Other current liabilities		145.3	Other current liabilities		46.5
Commodity derivatives	Other assets		--	Other assets		--	Other liabilities		--	Other liabilities		0.3
Total commodity derivatives			217.9			30.9			145.3			46.8
Total derivatives designated as hedging instruments		$	217.9		$	63.5		$	145.3		$	46.8

Derivatives not designated as hedging instruments
Interest rate derivatives	Other current assets	$	--	Other current assets	$	--	Other current liabilities	$	--	Other current liabilities	$	7.8
Commodity derivatives	Other current assets		8.1	Other current assets		7.6	Other current liabilities		0.7	Other current liabilities		5.5
Commodity derivatives	Other assets		0.6	Other assets		2.8	Other liabilities		1.4	Other liabilities		2.8
Total commodity derivatives			8.7			10.4			2.1			8.3
Total derivatives not designated as hedging instruments		$	8.7		$	10.4		$	2.1		$	16.1

Offsetting Financial Assets

	Offsetting of Financial Assets and Derivative Assets
										Gross Amounts Not Offset in the Balance Sheet
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Financial Instruments				Cash Collateral Received			Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)							(v) = (iii) + (iv)
As of December 31, 2014:
Commodity derivatives		$	226.6		$	--		$	226.6		$	(147.3	)	$	(23.9	)		$	55.4
As of December 31, 2013:
Interest rate derivatives		$	32.6		$	--		$	32.6		$	(2.6	)	$	--			$	30.0
Commodity derivatives			41.3			--			41.3			(41.0	)		--				0.3

Offsetting Financial Liabilities

	Offsetting of Financial Liabilities and Derivative Liabilities
										Gross Amounts Not Offset in the Balance Sheet
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Financial Instruments				Cash Collateral Paid				Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)								(v) = (iii) + (iv)
As of December 31, 2014:
Commodity derivatives		$	147.4		$	--		$	147.4		$	(147.3	)		$	--			$	0.1
As of December 31, 2013:
Interest rate derivatives		$	7.8		$	--		$	7.8		$	(2.6	)		$	--			$	5.2
Commodity derivatives			55.1			--			55.1			(41.0	)			(9.3	)			4.8

Derivative Instruments Effects on Statements of Operations

The following tables present the effect of our derivative instruments designated as fair value hedges on our Statements of Consolidated Operations for the periods indicated:

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Derivative
		For the Year Ended December 31,
		2014				2013				2012
Interest rate derivatives	Interest expense		$	(26.5	)		$	(13.1	)		$	2.7
Commodity derivatives	Revenue			11.9				(0.1	)			(6.4	)
Total			$	(14.6	)		$	(13.2	)		$	(3.7	)

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Year Ended December 31,
		2014				2013				2012
Interest rate derivatives	Interest expense		$	26.4			$	12.8			$	(2.9	)
Commodity derivatives	Revenue			(11.8	)			(5.7	)			19.1
Total			$	14.6			$	7.1			$	16.2

Derivative Instruments Effects on Statements of Comprehensive Income

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative (Effective Portion)
	For the Year Ended December 31,
	2014		2013			2012
Interest rate derivatives	$	--	$	6.6		$	(70.2	)
Commodity derivatives – Revenue (1)		161.3		(47.9	)		31.0
Commodity derivatives – Operating costs and expenses (1)		--		1.0			(13.7	)
Total	$	161.3	$	(40.3	)	$	(52.9	)

(1) The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.

Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income (Effective Portion)

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)
		For the Year Ended December 31,
		2014				2013				2012
Interest rate derivatives	Interest expense		$	(32.4	)		$	(29.2	)		$	(16.2	)
Commodity derivatives	Revenue			75.0				(22.4	)			10.1
Commodity derivatives	Operating costs and expenses			1.7				0.3				(24.3	)
Total			$	44.3			$	(51.3	)		$	(30.4	)

Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Derivatives in Cash Flow Hedging Relationships	Location	Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)
		For the Year Ended December 31,
		2014				2013			2012
Commodity derivatives	Revenue		$	(0.3	)		$	0.2		$	--
Commodity derivatives	Operating costs and expenses			--				--			0.3
Total			$	(0.3	)		$	0.2		$	0.3

Gain/(Loss) Recognized in Income on Derivative

The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the periods indicated:

Derivatives Not Designated as Hedging Instruments	Location	Gain (Loss) Recognized in Income on Derivative
		For the Year Ended December 31,
		2014				2013				2012
Interest rate derivatives	Interest expense		$	(0.1	)		$	(0.7	)		$	(5.6	)
Commodity derivatives	Revenue			(23.0	)			7.3				22.7
Commodity derivatives	Operating costs and expense			--				--				(2.8	)
Total			$	(23.1	)		$	6.6			$	14.3

Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis

	December 31, 2014 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets:
Commodity derivatives	$	37.8	$	187.8	$	1.0	$	226.6

Financial liabilities:
Liquidity Option Agreement	$	--	$	--	$	119.4	$	119.4
Commodity derivatives		13.8		133.0		0.6		147.4
Total	$	13.8	$	133.0	$	120.0	$	266.8

	December 31, 2013 Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets:
Interest rate derivatives	$	--	$	32.6	$	--	$	32.6
Commodity derivatives		17.2		20.2		3.9		41.3
Total	$	17.2	$	52.8	$	3.9	$	73.9

Financial liabilities:
Interest rate derivatives	$	--	$	7.8	$	--	$	7.8
Commodity derivatives		30.8		23.6		0.7		55.1
Total	$	30.8	$	31.4	$	0.7	$	62.9

Reconciliation of Changes in the Fair Value of Level 3 Financial Assets and Liabilities

The following table sets forth a reconciliation of changes in the fair values of our recurring Level 3 financial assets and liabilities on a combined basis for the periods indicated:

		For the Year Ended December 31,
	Location	2014			2013
Financial asset (liability) balance, net, January 1		$	3.2		$	(1.5	)
Total gains (losses) included in:
Net income (1)	Revenue		0.9			2.8
Other comprehensive income	Commodity derivative instruments – changes in fair value of cash flow hedges		(2.6	)		(0.9	)
Settlements			(3.4	)		1.6
Acquisition of Liquidity Option Agreement			(119.4	)		--
Transfers out of Level 3 (2)			2.3			1.2
Financial asset (liability) balance, net, December 31 (2)		$	(119.0	)	$	3.2

(1) There were $2.6 million and $4.4 million of unrealized losses and gains included in these amounts for the years ended December 31, 2014 and 2013, respectively. (2) Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2014 and 2013.

Fair Value Measurements, Valuation Techniques

The following tables provide quantitative information about our recurring Level 3 fair value measurements at the dates indicated:

	Fair Value At December 31, 2014
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	1.0	$	0.4	Discounted cash flow	Forward commodity prices	$49.26-$53.27/barrel
Commodity derivatives – Natural gas		--		0.2	Discounted cash flow	Forward commodity prices	$3.05-$4.09/MMBtu
Liquidity Option Agreement (see Note 18)		--		119.4	Discounted cash flow	Expected life of OTA following option exercise	30 years
						Estimated growth rates in Enterprise's earnings before interest, taxes, depreciation and amortization	3% to 14%
						OTA ownership interest in Enterprise common units	1.9% to 2.8%
						Interest rate on assumed debt of OTA following option exercise	4.9% over 30 years
						Forecasted yield on Enterprise common units	4.0% to 5.5%
						Federal and state tax rate	38%
Total	$	1.0	$	120.0

	Fair Value At December 31, 2013
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	3.9	$	0.7	Discounted cash flow	Forward commodity prices	$89.55-$98.54/barrel

Noncash Impairment Charges by Segment

The following table summarizes our non-cash impairment charges by segment during each of the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
NGL Pipelines & Services	$	16.2	$	30.6	$	16.3
Onshore Natural Gas Pipelines & Services		0.7		--		29.2
Onshore Crude Oil Pipelines & Services		2.9		30.1		10.6
Offshore Pipelines & Services		5.1		18.0		4.0
Petrochemical & Refined Products Services		9.1		18.7		3.3
Total	$	34.0	$	97.4	$	63.4

Nonrecurring Fair Value Measurements

			Fair Value Measurements Using
	Carrying Value at December 31, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Non-Cash Impairment Loss
Impairment of long-lived assets disposed of other than by sale	$	--		$	--		$	--		$	--		$	26.7
Impairment of long-lived assets to be disposed of by sale		1.5			--			--			1.5			7.3
Total													$	34.0

			Fair Value Measurements Using
	Carrying Value at December 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Non-Cash Impairment Loss
Impairment of long-lived assets disposed of other than by sale	$	--	$	--	$	--	$	--	$	79.4
Impairment of long-lived assets held and used		44.6		--		--		44.6		9.0
Impairment of long-lived assets to be disposed of by sale		0.6		--		--		0.6		9.0
Total									$	97.4

			Fair Value Measurements Using
	Carrying Value at December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Non-Cash Impairment Loss
Impairment of long-lived assets disposed of other than by sale	$	0.8	$	--	$	--	$	0.8	$	56.5
Impairment of long-lived assets held and used		2.2		--		--		2.2		2.6
Impairment of long-lived assets to be disposed of by sale		--		--		--		--		4.3
Total									$	63.4

Inventories (Tables)

12 Months Ended

Dec. 31, 2014

Inventories [Abstract]

Inventory Amounts by Product Type

Our inventory amounts by product type were as follows at the dates indicated:

	December 31,
	2014		2013
NGLs	$	579.1	$	593.8
Petrochemicals and refined products		295.6		395.1
Crude oil		97.8		42.6
Natural gas		41.7		61.6
Total	$	1,014.2	$	1,093.1

Cost of Sales and Lower of Cost or Market Adjustments

The following table presents our total cost of sales amounts and lower of cost or market adjustments for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Cost of sales (1)		$	40,464.1		$	40,770.2		$	36,015.5
Lower of cost or market adjustments			22.8			18.5			22.1
(1) Cost of sales is a component of "Operating costs and expenses," as presented on our Statements of Consolidated Operations. Year-to-year fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment and Accumulated Depreciation

The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:

	Estimated Useful Life	December 31,
	in Years	2014		2013
Plants, pipelines and facilities (1)	3-45 (6)	$	30,834.9	$	27,540.4
Underground and other storage facilities (2)	5-40 (7)		2,584.2		2,101.8
Platforms and facilities (3)	20-31		659.7		659.6
Transportation equipment (4)	3-10		154.2		138.9
Marine vessels (5)	15-30		796.4		744.8
Land			262.6		176.6
Construction in progress			2,754.7		2,655.5
Total			38,046.7		34,017.6
Less accumulated depreciation			8,165.1		7,071.0
Property, plant and equipment, net		$	29,881.6	$	26,946.6

(1) Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products 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 located in the Gulf of Mexico. (4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (7) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

Depreciation Expense and Capitalized Interest

The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Depreciation expense (1)		$	1,114.1		$	1,012.4		$	900.5
Capitalized interest (2)			77.9			133.0			116.8
(1) Depreciation expense is a component of "Costs and expenses" as presented on our Statements of Consolidated Operations. (2) Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.

AROs

The following table presents information regarding our AROs for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
ARO liability beginning balance	$	90.2		$	105.2		$	112.0
Liabilities incurred		0.1			1.7			1.7
Liabilities settled		(2.7	)		(14.2	)		(27.8	)
Revisions in estimated cash flows		4.6			(8.6	)		13.7
Accretion expense		6.1			6.1			5.6
ARO liability ending balance	$	98.3		$	90.2		$	105.2

Forecasted Accretion Expense Associated with AROs

The following table presents our forecast of accretion expense for the periods indicated:

2015			2016			2017			2018			2019
$	6.2		$	6.4		$	6.9		$	7.5		$	7.6

Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2014

Investments in Unconsolidated Affiliates [Abstract]

Investments in Unconsolidated Affiliates

The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method.

	Ownership Interest at December 31,	December 31,
	2014	2014		2013
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C. ("VESCO")	13.1%	$	27.7	$	27.6
K/D/S Promix, L.L.C. ("Promix")	50%		38.5		45.4
Baton Rouge Fractionators LLC ("BRF")	32.2%		18.8		19.5
Skelly-Belvieu Pipeline Company, L.L.C. ("Skelly-Belvieu")	50%		40.1		40.8
Texas Express Pipeline LLC ("Texas Express")	35%		349.3		339.9
Texas Express Gathering LLC ("TEG")	45%		37.9		37.8
Front Range Pipeline LLC ("Front Range")	33.3%		170.0		134.5
Onshore Natural Gas Pipelines & Services:
White River Hub, LLC ("White River Hub")	50%		23.2		24.2
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company LLC ("Seaway")	50%		1,431.2		940.7
Eagle Ford Pipeline LLC ("Eagle Ford Crude Oil Pipeline")	50%		336.5		224.5
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. ("Poseidon")	36%		31.8		41.7
Cameron Highway Oil Pipeline Company ("Cameron Highway")	50%		201.3		207.7
Deepwater Gateway, L.L.C. ("Deepwater Gateway")	50%		79.6		84.5
Neptune Pipeline Company, L.L.C. ("Neptune")	25.7%		34.9		38.7
Southeast Keathley Canyon Pipeline Company L.L.C. ("SEKCO")	50%		146.1		159.2
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC ("BRPC")	30%		6.5		7.6
Centennial Pipeline LLC ("Centennial")	50%		66.1		60.1
Other	Various		2.5		2.7
Total		$	3,042.0	$	2,437.1

The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
NGL Pipelines & Services	$	30.6		$	15.7		$	15.9
Onshore Natural Gas Pipelines & Services		3.6			3.8			4.4
Onshore Crude Oil Pipelines & Services		184.6			140.3			32.6
Offshore Pipelines & Services		54.0			29.8			26.9
Petrochemical & Refined Products Services (1)		(13.3	)		(22.3	)		(17.9	)
Other Investments (2)		--			--			2.4
Total	$	259.5		$	167.3		$	64.3

(1) Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value. (2) With respect to the year ended December 31, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.

The following table presents our unamortized excess cost amounts by business segment at the dates indicated:

	December 31,
	2014		2013
NGL Pipelines & Services	$	26.5	$	27.7
Onshore Crude Oil Pipelines & Services		21.7		17.8
Offshore Pipelines & Services		9.0		10.0
Petrochemical & Refined Products Services		2.4		2.6
Total	$	59.6	$	58.1

The following table presents our amortization of excess cost amounts by business segment for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
NGL Pipelines & Services	$	1.2	$	1.2	$	1.0
Onshore Crude Oil Pipelines & Services		0.9		0.7		0.7
Offshore Pipelines & Services		1.0		1.3		1.2
Petrochemical & Refined Products Services		0.2		0.1		0.2
Other Investments (1)		--		--		0.3
Total	$	3.3	$	3.3	$	3.4

(1) Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity through January 18, 2012, which is the date we ceased using the equity method to account for this investment.

The following table presents forecasted amortization of excess cost amounts for the years indicated.

2015			2016			2017			2018			2019
$	3.3		$	3.3		$	3.3		$	3.3		$	3.3

Acquisition of Oiltanking Partners, L.P. (Tables)

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Allocation of Total Purchase Prices Paid in Connection with Business Combinations

Consideration:
Cash	$	2,438.3
Equity instruments (54,807,352 common units of Enterprise) (1)		2,171.5
Fair value of total consideration transferred in Step 1	$	4,609.8

Identifiable assets acquired in business combination:
Current assets, including cash of $21.5 million	$	68.0
Property, plant and equipment		1,080.1
Identifiable intangible assets:
Customer relationship intangible assets (2)		1,192.4
Contract-based intangible assets (2)		297.5
IDRs		1,459.2
Total identifiable intangible assets		2,949.1
Other assets		227.6
Total assets acquired		4,324.8
Liabilities assumed in business combination:
Current liabilities		(84.8	)
Long-term debt		(223.3	)
Other long-term liabilities (3)		(129.7	)
Total liabilities assumed		(437.8	)
Noncontrolling interest in Oiltanking (4)		(1,397.2	)
Total assets acquired less liabilities assumed and noncontrolling interest		2,489.8
Total consideration given for ownership interests in Oiltanking in Step 1		4,609.8
Goodwill	$	2,120.0

(1) The fair value of the equity-based consideration paid in connection with Step 1 of the Oiltanking acquisition was based on the closing market price of Enterprise's common units of $39.62 per unit on the acquisition date. (2) The weighted-average amortization period for the customer relationship intangible assets is 29 years and for the contract-based intangible assets is six years. (3) Other long-term liabilities includes $119.4 million for the Liquidity Option Agreement. The fair value assigned to the Liquidity Option Agreement is provisional pending completion of certain tax-related computations. See Note 18 for information regarding this agreement. (4) From an accounting perspective, Enterprise acquired control of Oiltanking as a result of completing Step 1. In accordance with ASC 805, Business Combinations, the estimated fair value of Oiltanking's common units held by parties other than Enterprise following Step 1 (i.e., the "noncontrolling interest") is based on 28,328,890 common units held by third parties on October 1, 2014 multiplied by the closing unit price for Oiltanking common units on that date of $49.32 per unit.

Oiltanking IDR Distribution Targets

		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit Target Amount	Unitholders	General Partner
Minimum quarterly distribution	$0.16875	98%	2%
First target distribution	above $0.16875 up to $0.1940625	98%	2%
Second target distribution	above $0.1940625 up to $0.2109375	85%	15%
Third target distribution	above $0.2109375 up to $0.253125	75%	25%
Thereafter	above $0.253125	50%	50%

Unaudited Pro Forma Earnings Information

	For Year Ended December 31,
	2014		2013
Pro forma earnings data:
Revenues	$	48,087.5	$	47,875.7
Costs and expenses		44,509.0		44,522.3
Operating income		3,838.0		3,520.7
Net income		2,877.5		2,632.8
Net income attributable to noncontrolling interest		75.0		39.5
Net income attributable to limited partners		2,802.5		2,593.3

Basic earnings per unit:
As reported basic units outstanding		1,848.7		1,788.0
Pro forma basic units outstanding		1,903.5		1,842.8
As reported basic earnings per unit	$	1.51	$	1.45
Pro forma basic earnings per unit	$	1.47	$	1.41
Diluted earnings per unit:
As reported diluted units outstanding		1,895.2		1,842.6
Pro forma diluted units outstanding		1,950.0		1,897.4
As reported diluted earnings per unit	$	1.47	$	1.41
Pro forma diluted earnings per unit	$	1.44	$	1.37

Intangible Assets and Goodwill (Tables)

12 Months Ended

Dec. 31, 2014

Intangible Assets and Goodwill [Abstract]

Intangible Assets by Segment

The following table summarizes our intangible assets by business segment at the dates indicated:

	December 31, 2014							December 31, 2013
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	340.8	$	(183.2	)	$	157.6	$	340.8	$	(165.7	)	$	175.1
Contract-based intangibles		277.7		(178.7	)		99.0		281.3		(171.2	)		110.1
Incentive distribution rights		432.6		--			432.6		--		--			--
Segment total		1,051.1		(361.9	)		689.2		622.1		(336.9	)		285.2
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles		1,163.6		(308.9	)		854.7		1,163.6		(281.2	)		882.4
Contract-based intangibles		466.0		(347.8	)		118.2		466.1		(330.7	)		135.4
Segment total		1,629.6		(656.7	)		972.9		1,629.7		(611.9	)		1,017.8
Onshore Crude Oil Pipelines & Services:
Customer relationship intangibles		1,108.0		(7.7	)		1,100.3		10.7		(6.3	)		4.4
Contract-based intangibles		281.4		(13.5	)		267.9		0.4		(0.3	)		0.1
Incentive distribution rights		855.4		--			855.4		--		--			--
Segment total		2,244.8		(21.2	)		2,223.6		11.1		(6.6	)		4.5
Offshore Pipelines & Services:
Customer relationship intangibles		195.8		(154.9	)		40.9		203.9		(150.0	)		53.9
Contract-based intangibles		1.2		(0.5	)		0.7		1.2		(0.4	)		0.8
Segment total		197.0		(155.4	)		41.6		205.1		(150.4	)		54.7
Petrochemical & Refined Products Services:
Customer relationship intangibles		198.4		(43.3	)		155.1		104.3		(38.2	)		66.1
Contract-based intangibles		56.3		(7.8	)		48.5		39.9		(6.0	)		33.9
Incentive distribution rights		171.2		--			171.2		--		--			--
Segment total		425.9		(51.1	)		374.8		144.2		(44.2	)		100.0
Total all segments	$	5,548.4	$	(1,246.3	)	$	4,302.1	$	2,612.2	$	(1,150.0	)	$	1,462.2

Amortization Expense of Intangible Assets by Segment

The following table presents the amortization expense of our intangible assets by business segment for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
NGL Pipelines & Services	$	33.1	$	36.4	$	39.7
Onshore Natural Gas Pipelines & Services		45.0		50.1		63.4
Onshore Crude Oil Pipelines & Services		15.7		1.4		0.9
Offshore Pipelines & Services		9.9		11.5		11.3
Petrochemical & Refined Products Services		6.9		6.2		10.4
Total	$	110.6	$	105.6	$	125.7

Forecasted Amortization Expense

The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated:

2015			2016			2017			2018			2019
$	150.5		$	152.3		$	149.3		$	142.7		$	131.3

Significant Acquired Intangible Assets

§	Oiltanking customer relationships – We recorded customer relationship intangible assets in connection with the Oiltanking acquisition in October 2014 (see Note 10). The carrying values of these intangible assets at December 31, 2014 are presented in the following table:

	Gross Value		Accumulated Amortization			Carrying Value
Onshore Crude Oil Pipelines & Services:
Oiltanking customer relationships	$	1,098.4	$	(1.4	)	$	1,097.0
Petrochemical & Refined Products Services:
Oiltanking customer relationships		94.1		--			94.1
Total	$	1,192.5	$	(1.4	)	$	1,191.1

	Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Fairplay natural gas processing customer relationships	$	103.4	$	(27.2	)	$	76.2
Onshore Natural Gas Pipelines & Services:
State Line natural gas gathering customer relationships		675.0		(68.7	)		606.3
Fairplay natural gas gathering customer relationships		116.6		(30.7	)		85.9
Total	$	895.0	$	(126.6	)	$	768.4

§	Oiltanking customer contracts – We recorded customer contract intangible assets in connection with the Oiltanking acquisition in October 2014 (see Note 10). The carrying values of these intangible assets at December 31, 2014 are presented in the following table:

	Gross Value		Accumulated Amortization			Carrying Value
Onshore Crude Oil Pipelines & Services:
Oiltanking customer contracts	$	281.0	$	(13.2	)	$	267.8
Petrochemical & Refined Products Services:
Oiltanking customer contracts		16.4		(0.7	)		15.7
Total	$	297.4	$	(13.9	)	$	283.5

Changes in Carrying Amount of Goodwill

	NGL Pipelines & Services		Onshore Natural Gas Pipelines & Services		Onshore Crude Oil Pipelines & Services			Offshore Pipelines & Services			Petrochemical & Refined Products Services			Consolidated Total
Balance at December 31, 2011	$	341.2	$	296.3	$	311.2		$	82.1		$	1,061.5		$	2,092.3
Reclassification to assets held for sale		--		--		--			--			(5.5	)		(5.5	)
Balance at December 31, 2012		341.2		296.3		311.2			82.1			1,056.0			2,086.8
Goodwill related to the sale of assets		--		--		(6.1	)		--			(0.7	)		(6.8	)
Balance at December 31, 2013		341.2		296.3		305.1			82.1			1,055.3			2,080.0
Reclassification of goodwill		520.0		--		--			--			(520.0	)		--
Goodwill related to the sale of assets		--		--		--			(0.1	)		--			(0.1	)
Goodwill related to Oiltanking acquisition		1,319.2		--		554.8			--			246.0			2,120.0
Balance at December 31, 2014	$	2,180.4	$	296.3	$	859.9		$	82.0		$	781.3		$	4,199.9

Debt Obligations (Tables)

12 Months Ended

Dec. 31, 2014

Debt Obligations [Abstract]

Consolidated Debt Obligations

The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:

	December 31,
	2014			2013
EPO senior debt obligations:
Commercial Paper Notes, variable-rate (1)	$	906.5		$	475.0
Senior Notes O, 9.75% fixed-rate, due January 2014		--			500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		--			650.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0			250.0
Senior Notes X, 3.70% fixed-rate, due June 2015		400.0			400.0
Senior Notes FF, 1.25% fixed-rate, due August 2015		650.0			650.0
$1.5 Billion 364-Day Credit Agreement, variable-rate, due September 2015		--			--
Senior Notes AA, 3.20% fixed-rate, due February 2016		750.0			750.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0			800.0
Senior Notes V, 6.65% fixed-rate, due April 2018		349.7			349.7
$3.5 Billion Multi-Year Revolving Credit Facility, variable-rate, due June 2018		--			--
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0			700.0
Senior Notes LL,2.55% fixed-rate, due October 2019		800.0			--
Senior Notes Q, 5.25% fixed-rate, due January 2020		500.0			500.0
Senior Notes Y, 5.20% fixed-rate, due September 2020		1,000.0			1,000.0
Senior Notes CC, 4.05% fixed-rate, due February 2022		650.0			650.0
Senior Notes HH, 3.35% fixed-rate, due March 2023		1,250.0			1,250.0
Senior Notes JJ, 3.90% fixed-rate, due February 2024		850.0			--
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150.0			--
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0			500.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0			350.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0			250.0
Senior Notes W, 7.55% fixed-rate, due April 2038		399.6			399.6
Senior Notes R, 6.125% fixed-rate, due October 2039		600.0			600.0
Senior Notes Z, 6.45% fixed-rate, due September 2040		600.0			600.0
Senior Notes BB, 5.95% fixed-rate, due February 2041		750.0			750.0
Senior Notes DD, 5.70% fixed-rate, due February 2042		600.0			600.0
Senior Notes EE, 4.85% fixed-rate, due August 2042		750.0			750.0
Senior Notes GG, 4.45% fixed-rate, due February 2043		1,100.0			1,100.0
Senior Notes II, 4.85% fixed-rate, due March 2044		1,400.0			1,000.0
Senior Notes KK, 5.10% fixed-rate, due February 2045		1,150.0			--
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			--
TEPPCO senior debt obligations:
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018		0.3			0.3
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038		0.4			0.4
Total principal amount of senior debt obligations		19,856.5			15,825.0
EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 (2)		550.0			550.0
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 (3)		285.8			285.8
EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068 (4)		682.7			682.7
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067		14.2			14.2
Total principal amount of senior and junior debt obligations		21,389.2			17,357.7
Other, non-principal amounts		(25.4	)		(6.2	)
Less current maturities of debt (5)		(2,206.4	)		(1,125.0	)
Total long-term debt	$	19,157.4		$	16,226.5

(1) Principal amounts outstanding at December 31, 2014 have interest rates ranging from 0.22% and 0.77% and are due in January 2015. (2) Fixed rate of 8.375% through August 1, 2016; thereafter, variable rate based on 3-month LIBOR plus 3.7075%. (3) Fixed rate of 7.00% through September 1, 2017; thereafter, variable rate based on 3-month LIBOR plus 2.7775%. (4) Fixed rate of 7.034% through January 15, 2018; thereafter, the rate will be the greater of 7.034% or a variable rate based on 3-month LIBOR plus 2.68%. (5) We expect to refinance the current maturities of our debt obligations at or prior to their maturity.

Consolidated Debt Maturities

The following table presents contractually scheduled maturities of our consolidated debt obligations outstanding at December 31, 2014 for the next five years, and in total thereafter:

			Scheduled Maturities of Debt
	Total		2015		2016		2017		2018		2019		Thereafter
Commercial Paper	$	906.5	$	906.5	$	--	$	--	$	--	$	--	$	--
Senior Notes		18,950.0		1,300.0		750.0		800.0		350.0		1,500.0		14,250.0
Junior Subordinated Notes		1,532.7		--		--		--		--		--		1,532.7
Total	$	21,389.2	$	2,206.5	$	750.0	$	800.0	$	350.0	$	1,500.0	$	15,782.7

Junior Subordinated Notes Interest Rate Terms

The following table summarizes the interest rate terms of our junior subordinated notes:

Series	Fixed Annual Interest Rate	Variable Annual Interest Rate Thereafter
Junior Subordinated Notes A	8.375% through August 2016 (1)	3-month LIBOR rate + 3.708% (4)
Junior Subordinated Notes B	7.034% through January 2018 (2)	Greater of: (i) 3-month LIBOR rate + 2.68% or (ii) 7.034% (5)
Junior Subordinated Notes C	7.00% through September 2017 (3)	3-month LIBOR rate + 2.778% (6)
(1) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007. (2) Interest is payable semi-annually in arrears in January and July of each year, which commenced in January 2008. (3) Interest is payable semi-annually in arrears in June and December of each year, which commenced in December 2009. (4) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. (5) Interest is payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. (6) Interest is payable quarterly in arrears in March, June, September and December of each year commencing in June 2017.

Interest Rates and Weighted-Average Interest Rates Paid on Consolidated Variable-Rate Debt Obligations

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the year ended December 31, 2014:

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
EPO $3.5 Billion Multi-Year Revolving Credit Facility	1.13% to 1.14%	1.13%
EPO $1.5 Billion 364-Day Credit Agreement	1.15% to 1.15%	1.15%

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
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-Number 210
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Summary of Changes in Outstanding Units

Equity and Distributions (Tables)

12 Months Ended

Dec. 31, 2014

Equity and Distributions [Abstract]

	Common Units (Unrestricted)			Restricted Common Units			Total Common Units
Number of units outstanding at December 31, 2011		1,755,504,404			7,736,432			1,763,240,836
Common units issued in connection with underwritten offering		18,400,000			--			18,400,000
Common units issued in connection with at-the-market program		7,957,090			--			7,957,090
Common units issued in connection with DRIP and EUPP		5,629,320			--			5,629,320
Common units issued in connection with the vesting and exercise of unit options		427,828			--			427,828
Common units issued in connection with the vesting of restricted common unit awards		2,633,206			(2,633,206	)		--
Common units issued in connection with the vesting of other types of equity-based awards		104,336			--			104,336
Restricted common unit awards issued		--			3,177,476			3,177,476
Forfeiture of restricted common unit awards		--			(493,730	)		(493,730	)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards		(816,482	)		--			(816,482	)
Number of units outstanding at December 31, 2012		1,789,839,702			7,786,972			1,797,626,674
Common units issued in connection with underwritten offering		36,800,000			--			36,800,000
Common units issued in connection with at-the-market program		15,249,378			--			15,249,378
Common units issued in connection with DRIP and EUPP		10,308,254			--			10,308,254
Common units issued in connection with the vesting and exercise of unit options		401,764			--			401,764
Common units issued in connection with the vesting of restricted common unit awards		3,770,696			(3,770,696	)		--
Conversion and reclassification of Class B units to common units		9,040,862			--			9,040,862
Restricted common unit awards issued		--			3,549,052			3,549,052
Forfeiture of restricted common unit awards		--			(344,114	)		(344,114	)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards		(1,261,854	)		--			(1,261,854	)
Number of units outstanding at December 31, 2013		1,864,148,802			7,221,214			1,871,370,016
Common units issued in connection with at-the-market program		1,590,334			--			1,590,334
Common units issued in connection with DRIP and EUPP		9,754,227			--			9,754,227
Common units issued in connection with Step 1 of Oiltanking acquisition		54,807,352			--			54,807,352
Common units issued in connection with the vesting and exercise of unit options		1,014,108			--			1,014,108
Common units issued in connection with the vesting of phantom unit awards		23,311			--			23,311
Common units issued in connection with the vesting of restricted common unit awards		2,634,074			(2,634,074	)		--
Forfeiture of restricted common unit awards		--			(357,350	)		(357,350	)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards		(894,383	)		--			(894,383	)
Other		17,202			--			17,202
Number of units outstanding at December 31, 2014		1,933,095,027			4,229,790			1,937,324,817

Components of Accumulated Other Comprehensive Income (Loss)

The following tables present the components of accumulated other comprehensive income (loss) as reported on our Consolidated Balance Sheets at the dates indicated:

	Gains (Losses) on Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other		Total
Balance, December 31, 2012	$	10.1		$	(383.0	)	$	2.5	$	(370.4	)
Other comprehensive income before reclassifications		(46.9	)		6.6			0.4		(39.9	)
Amounts reclassified from accumulated other comprehensive loss		22.1			29.2			--		51.3
Total other comprehensive income (loss)		(24.8	)		35.8			0.4		11.4
Balance, December 31, 2013		(14.7	)		(347.2	)		2.9		(359.0	)
Other comprehensive income before reclassifications		161.3			--			0.4		161.7
Amounts reclassified from accumulated other comprehensive (income) loss		(76.7	)		32.4			--		(44.3	)
Total other comprehensive income		84.6			32.4			0.4		117.4
Balance, December 31, 2014	$	69.9		$	(314.8	)	$	3.3	$	(241.6	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss) Into Net Income

The following table presents reclassifications out of accumulated other comprehensive income (loss) into net income for the periods indicated:

		For the Year Ended December 31,
	Location	2014			2013
Losses (gains) on cash flow hedges:
Interest rate derivatives	Interest expense	$	32.4		$	29.2
Commodity derivatives	Revenue		(75.0	)		22.4
Commodity derivatives	Operating costs and expenses		(1.7	)		(0.3	)
Total		$	(44.3	)	$	51.3

Components of Noncontrolling Interests

The following table presents additional information regarding noncontrolling interests as presented on our Consolidated Balance Sheets at the dates indicated:

	December 31,
	2014			2013
Limited partners of Oiltanking other than EPO		$	1,408.9		$	--
Joint venture partners			220.1			225.6
Total		$	1,629.0		$	225.6

Components of Net Income Attributable to Noncontrolling Interests

The following table presents the components of net income attributable to noncontrolling interests as presented on our Statements of Consolidated Operations for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Limited partners of Oiltanking other than EPO		$	14.2		$	--		$	--
Joint venture partners			31.9			10.2			8.1
Total		$	46.1		$	10.2		$	8.1

Cash Distributions Paid to and Cash Contributions Received From Noncontrolling Interests

	For the Year Ended December 31,
	2014		2013		2012
Cash distributions paid to noncontrolling interests:
Limited partners of Oiltanking other than EPO	$	7.7	$	--	$	--
Joint venture partners		40.9		8.9		13.3
Total	$	48.6	$	8.9	$	13.3

Cash contributions from noncontrolling interests:
Joint venture partners	$	4.0	$	115.4	$	6.6

Declared Quarterly Cash Distribution Rates

	Distribution Per Common Unit		Record Date	Payment Date
2013:
1st Quarter	$	0.3350	4/30/2013	5/7/2013
2nd Quarter	$	0.3400	7/31/2013	8/7/2013
3rd Quarter	$	0.3450	10/31/2013	11/7/2013
4th Quarter	$	0.3500	1/31/2014	2/7/2014
2014:
1st Quarter	$	0.3550	4/30/2014	5/7/2014
2nd Quarter	$	0.3600	7/31/2014	8/7/2014
3rd Quarter	$	0.3650	10/31/2014	11/7/2014
4th Quarter	$	0.3700	1/30/2015	2/6/2015

Business Segments (Tables)

12 Months Ended

Dec. 31, 2014

Business Segments [Abstract]

Measurement of Total Segment Gross Operating Margin

The following table presents our measurement of non-GAAP total segment gross operating margin for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Revenues	$	47,951.2		$	47,727.0		$	42,583.1
Subtract operating costs and expenses		(44,220.5	)		(44,238.7	)		(39,367.9	)
Add equity in income of unconsolidated affiliates		259.5			167.3			64.3
Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin		1,282.7			1,148.9			1,061.7
Add impairment charges not reflected in gross operating margin		34.0			92.6			63.4
Subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin		(102.1	)		(83.4	)		(17.6	)
Add non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin (1)		84.6			4.4			--
Subtract subsequent recognition of deferred revenues attributable to make-up rights		(2.9	)		--			--
Total segment gross operating margin	$	5,286.5		$	4,818.1		$	4,387.0

(1) Several of our major new liquids pipeline projects experienced periods in 2013 and 2014 where shippers were unable to meet their contractual minimum volume commitments.

Reconciliation of Total Segment Gross Operating Margin to Operating Income and Income Before Provision for Income Taxes

The following table presents a reconciliation of total segment gross operating margin to operating income and further to income before income taxes for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Total segment gross operating margin	$	5,286.5		$	4,818.1		$	4,387.0
Adjustments to reconcile total segment gross operating margin to operating income:
Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin		(1,282.7	)		(1,148.9	)		(1,061.7	)
Subtract impairment charges not reflected in gross operating margin		(34.0	)		(92.6	)		(63.4	)
Add net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin (see Note 20)		102.1			83.4			17.6
Subtract non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin		(84.6	)		(4.4	)		--
Add subsequent recognition of deferred revenues attributable to make-up rights		2.9			--			--
Subtract general and administrative costs not reflected in gross operating margin		(214.5	)		(188.3	)		(170.3	)
Operating income		3,775.7			3,467.3			3,109.2
Other expense, net		(919.1	)		(802.7	)		(698.4	)
Income before income taxes	$	2,856.6		$	2,664.6		$	2,410.8

Information by Business Segments

Information by business segment, together with reconciliations to our consolidated financial statement totals, is presented in the following table:

	Reportable Business Segments
	NGL Pipelines & Services		Onshore Natural Gas Pipelines & Services		Onshore Crude Oil Pipelines & Services		Offshore Pipelines & Services		Petrochemical & Refined Products Services			Other Investments		Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Year ended December 31, 2014	$	17,078.4	$	4,182.6	$	20,151.9	$	150.3	$	6,316.5		$	--	$	--		$	47,879.7
Year ended December 31, 2013		17,119.1		3,522.7		20,609.1		151.7		6,258.5			--		--			47,661.1
Year ended December 31, 2012		15,158.9		3,297.7		17,661.6		182.7		6,208.9			--		--			42,509.8
Revenues from related parties:
Year ended December 31, 2014		11.4		21.2		32.4		6.5		--			--		--			71.5
Year ended December 31, 2013		1.1		15.8		41.3		7.7		--			--		--			65.9
Year ended December 31, 2012		9.5		54.9		0.1		8.8		--			--		--			73.3
Intersegment and intrasegment revenues:
Year ended December 31, 2014		13,716.5		1,106.7		12,678.7		6.5		1,779.6			--		(29,288.0	)		--
Year ended December 31, 2013		11,096.6		959.7		10,222.3		9.6		1,764.0			--		(24,052.2	)		--
Year ended December 31, 2012		12,500.6		871.6		6,906.9		10.4		1,758.9			--		(22,048.4	)		--
Total revenues:
Year ended December 31, 2014		30,806.3		5,310.5		32,863.0		163.3		8,096.1			--		(29,288.0	)		47,951.2
Year ended December 31, 2013		28,216.8		4,498.2		30,872.7		169.0		8,022.5			--		(24,052.2	)		47,727.0
Year ended December 31, 2012		27,669.0		4,224.2		24,568.6		201.9		7,967.8			--		(22,048.4	)		42,583.1
Equity in income (loss) of unconsolidated affiliates:
Year ended December 31, 2014		30.6		3.6		184.6		54.0		(13.3	)		--		--			259.5
Year ended December 31, 2013		15.7		3.8		140.3		29.8		(22.3	)		--		--			167.3
Year ended December 31, 2012		15.9		4.4		32.6		26.9		(17.9	)		2.4		--			64.3
Gross operating margin:
Year ended December 31, 2014		2,877.7		803.3		762.5		162.0		681.0			--		--			5,286.5
Year ended December 31, 2013		2,514.4		789.0		742.7		146.1		625.9			--		--			4,818.1
Year ended December 31, 2012		2,468.5		775.5		387.7		173.0		579.9			2.4		--			4,387.0
Property, plant and equipment, net: (see Note 8)
At December 31, 2014		11,766.9		8,835.5		2,332.2		1,145.1		3,047.2			--		2,754.7			29,881.6
At December 31, 2013		9,957.8		8,917.3		1,479.9		1,223.7		2,712.4			--		2,655.5			26,946.6
At December 31, 2012		8,494.8		8,950.1		1,385.9		1,343.0		2,559.5			--		2,113.1			24,846.4
Investments in unconsolidated affiliates: (see Note 9)
At December 31, 2014		682.3		23.2		1,767.7		493.7		75.1			--		--			3,042.0
At December 31, 2013		645.5		24.2		1,165.2		531.8		70.4			--		--			2,437.1
At December 31, 2012		324.6		24.9		493.8		479.0		72.3			--		--			1,394.6
Intangible assets, net: (see Note 11)
At December 31, 2014		689.2		972.9		2,223.6		41.6		374.8			--		--			4,302.1
At December 31, 2013		285.2		1,017.8		4.5		54.7		100.0			--		--			1,462.2
At December 31, 2012		320.6		1,067.9		5.9		66.2		106.2			--		--			1,566.8
Goodwill: (see Note 11)
At December 31, 2014		2,180.4		296.3		859.9		82.0		781.3			--		--			4,199.9
At December 31, 2013		341.2		296.3		305.1		82.1		1,055.3			--		--			2,080.0
At December 31, 2012		341.2		296.3		311.2		82.1		1,056.0			--		--			2,086.8
Segment assets:
At December 31, 2014		15,318.8		10,127.9		7,183.4		1,762.4		4,278.4			--		2,754.7			41,425.6
At December 31, 2013		11,229.7		10,255.6		2,954.7		1,892.3		3,938.1			--		2,655.5			32,925.9
At December 31, 2012		9,481.2		10,339.2		2,196.8		1,970.3		3,794.0			--		2,113.1			29,894.6

Consolidated Revenues and Expenses

The following table presents additional information regarding our consolidated revenues and costs and expenses for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
NGL Pipelines & Services:
Sales of NGLs and related products	$	15,460.1		$	15,916.0		$	14,218.5
Midstream services		1,629.7			1,204.2			949.9
Total		17,089.8			17,120.2			15,168.4
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		3,181.7			2,571.6			2,395.4
Midstream services		1,022.1			966.9			957.2
Total		4,203.8			3,538.5			3,352.6
Onshore Crude Oil Pipelines & Services:
Sales of crude oil		19,783.9			20,371.3			17,548.7
Midstream services		400.4			279.1			113.0
Total		20,184.3			20,650.4			17,661.7
Offshore Pipelines & Services:
Sales of natural gas		0.3			0.5			0.4
Sales of crude oil		8.6			5.7			3.3
Midstream services		147.9			153.2			187.8
Total		156.8			159.4			191.5
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		5,575.5			5,568.8			5,470.9
Midstream services		741.0			689.7			738.0
Total		6,316.5			6,258.5			6,208.9
Total consolidated revenues	$	47,951.2		$	47,727.0		$	42,583.1

Consolidated costs and expenses
Operating costs and expenses:
Cost of sales	$	40,464.1		$	40,770.2		$	36,015.5
Other operating costs and expenses (1)		2,541.8			2,310.4			2,244.9
Depreciation, amortization and accretion		1,282.7			1,148.9			1,061.7
Net gains attributable to asset sales and insurance recoveries		(102.1	)		(83.4	)		(17.6	)
Non-cash asset impairment charges		34.0			92.6			63.4
General and administrative costs		214.5			188.3			170.3
Total consolidated costs and expenses	$	44,435.0		$	44,427.0		$	39,538.2

(1) Represents cost of operating our plants, pipelines and other fixed assets, excluding depreciation, amortization and accretion charges.

NGL Pipelines & Services	$	615.5
Onshore Natural Gas Pipelines & Services		130.3
Onshore Crude Oil Pipelines & Services		3,106.0
Offshore Pipelines & Services		6.7
Petrochemical & Refined Products Services		194.2
Total	$	4,052.7

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2014

The following table summarizes our related party transactions for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Revenues – related parties:
Unconsolidated affiliates		$	71.5		$	65.9		$	73.3
Costs and expenses – related parties:
EPCO and affiliates		$	939.9		$	892.2		$	816.9
Unconsolidated affiliates			183.0			160.0			40.2
Total		$	1,122.9		$	1,052.2		$	857.1

The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated:

	December 31,
	2014		2013
Accounts receivable - related parties:
Unconsolidated affiliates	$	2.8	$	6.8

Accounts payable - related parties:
EPCO and affiliates	$	98.1	$	116.3
Unconsolidated affiliates		20.8		34.2
Total	$	118.9	$	150.5

EPCO and affiliates [Member]

The following table presents our costs and expenses attributable to the ASA and other related party transactions with EPCO for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Operating costs and expenses		$	801.7		$	770.7		$	719.4
General and administrative expenses			138.2			121.5			97.5
Total costs and expenses		$	939.9		$	892.2		$	816.9

Schedule of Related Party Transactions

Number of Units	Percentage of Total Units Outstanding
684,721,631	35.3%

Provision for Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Provision for Income Taxes [Abstract]

Federal and State Income Tax Provision

Our federal and state income tax provision (benefit) is summarized below:

	For the Year Ended December 31,
	2014		2013			2012
Current:
Federal	$	2.2	$	(0.5	)	$	18.9
State		13.4		19.3			28.9
Foreign		1.4		0.8			1.2
Total current		17.0		19.6			49.0
Deferred:
Federal		2.2		(0.5	)		(64.7	)
State		3.5		38.9			(1.4	)
Foreign		0.4		(0.5	)		(0.1	)
Total deferred		6.1		37.9			(66.2	)
Total provision for (benefit from) income taxes	$	23.1	$	57.5		$	(17.2	)

Reconciliation of Provision for Income Taxes

A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:

	For the Year Ended December 31,
	2014			2013			2012
Pre-Tax Net Book Income ("NBI")	$	2,856.6		$	2,664.6		$	2,410.8

Texas Margin Tax (1)	$	17.5		$	58.3		$	23.5
State income taxes (net of federal benefit)		0.2			(0.1	)		5.3
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities		1.5			(1.4	)		(1.6	)
Valuation allowance					--			(2.0	)
Expiration of tax net operating loss		--			0.1			2.4
Tax gain on conversion of corporate subsidiaries into limited liability companies		--			--			(45.3	)
Other permanent differences		3.9			0.6			0.5
Provision for (benefit from) income taxes	$	23.1		$	57.5		$	(17.2	)

Effective income tax rate		0.8	%		2.2	%		(0.7	)%

(1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.

Components of Deferred Tax Assets and Liabilities

The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated:

	At December 31,
	2014		2013
Deferred tax assets:
Net operating loss carryovers (1)	$	0.3	$	0.1
Employee benefit plans		0.3		0.2
Accruals		1.5		2.0
Total deferred tax assets		2.1		2.3
Less: Deferred tax liabilities:
Property, plant and equipment		64.4		59.8
Equity investment in partnerships		4.1		2.9
Total deferred tax liabilities		68.5		62.7
Total net deferred tax liabilities	$	66.4	$	60.4

Current portion of total net deferred tax assets	$	0.2	$	0.4
Long-term portion of total net deferred tax liabilities	$	66.6	$	60.8

(1) These losses expire in various years between 2015 and 2028 and are subject to limitations on their utilization.

Earnings Per Unit (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Unit [Abstract]

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 Year Ended December 31,
	2014			2013		2012
BASIC EARNINGS PER UNIT
Net income attributable to limited partners	$	2,787.4		$	2,596.9	$	2,419.9
Undistributed earnings allocated and cash payments on phantom unit awards (1)		(5.2	)		--		--
Net income available to common unitholders	$	2,782.2		$	2,596.9	$	2,419.9

Basic weighted-average number of common units outstanding		1,848.7			1,788.0		1,723.6

Basic earnings per unit	$	1.51		$	1.45	$	1.40

DILUTED EARNINGS PER UNIT
Net income attributable to limited partners	$	2,787.4		$	2,596.9	$	2,419.9

Diluted weighted-average number of units outstanding:
Distribution-bearing common units		1,848.7			1,788.0		1,723.6
Designated Units		42.7			46.8		51.0
Class B units (2)		--			5.4		9.0
Phantom units (1)		2.9			--		--
Incremental option units		0.9			2.4		2.8
Total		1,895.2			1,842.6		1,786.4

Diluted earnings per unit	$	1.47		$	1.41	$	1.35

(1) Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to Enterprise's common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit. Phantom unit awards were first issued in February 2014. (2) The Class B units automatically converted into an equal number of distribution-bearing common units in August 2013.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies [Abstract]

Summary of Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2014. A description of each type of contractual obligation follows:

	Payment or Settlement due by Period
Contractual Obligations	Total		2015		2016		2017		2018		2019		Thereafter
Scheduled maturities of debt obligations	$	21,389.2	$	2,206.5	$	750.0	$	800.0	$	350.0	$	1,500.0	$	15,782.7
Estimated cash interest payments	$	21,303.9	$	1,005.6	$	968.6	$	953.0	$	899.6	$	846.8	$	16,630.3
Operating lease obligations	$	542.7	$	60.5	$	62.0	$	56.4	$	48.9	$	42.3	$	272.6
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	2,139.7	$	637.5	$	539.1	$	295.5	$	295.5	$	195.1	$	177.0
NGLs	$	487.0	$	391.1	$	26.4	$	26.3	$	28.9	$	14.3	$	--
Crude oil	$	2,425.2	$	2,279.1	$	37.4	$	37.3	$	37.3	$	34.1	$	--
Petrochemicals & refined products	$	1,499.3	$	956.7	$	493.1	$	49.5	$	--	$	--	$	--
Other	$	71.8	$	38.1	$	9.2	$	6.9	$	4.2	$	4.2	$	9.2
Underlying major volume commitments:
Natural gas (in TBtus)		879		255		219		128		128		82		67
NGLs (in MMBbls)		30		17		3		4		4		2		--
Crude oil (in MMBbls)		41		38		1		1		1		--		--
Petrochemicals & refined products (in MMBbls)		23		15		7		1		--		--		--
Service payment commitments	$	850.8	$	200.6	$	181.4	$	154.9	$	86.7	$	66.1	$	161.1
Capital expenditure commitments	$	1,299.8	$	1,299.8	$	--	$	--	$	--	$	--	$	--

Schedule of Other Liabilities

The following table summarizes the components of "Other long-term liabilities" as presented on Consolidated Balance Sheets at the dates indicated:

	December 31,
	2014		2013
Noncurrent portion of asset retirement obligations (see Note 8)	$	83.2	$	82.5
Deferred revenues – non-current portion (see Note 2)		73.0		54.6
Liquidity Option Agreement (see Note 10)		119.4		--
Centennial guarantees		7.0		7.8
Other		28.2		27.4
Total	$	310.8	$	172.3

Liquidity Option Agreement [Table Text Block]

Scenario	Number of Enterprise Common Units Held at Exercise Date	Discounted Cash Flows		Probability Assigned to Each Scenario	Probability Weighted Cash Flows
	(in millions)
M&B exercises option; OTA owns 100% of units	54.8	$	164.7	50%	$	82.4
M&B exercises option; OTA owns 75% of units	41.1		123.5	20%		24.7
M&B exercises option; OTA owns 50% of units	27.4		82.4	10%		8.2
M&B exercises option; OTA owns 25% of units	13.7		41.2	10%		4.1
M&B does not exercise option	--		--	10%		--
Totals				100%	$	119.4

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Information [Abstract]

Net Effect of Changes in Operating Assets and Liabilities

The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Decrease (increase) in:
Accounts receivable – trade	$	1,685.4		$	(1,136.2	)	$	161.5
Accounts receivable – related parties		3.8			(3.6	)		35.3
Inventories		(105.6	)		38.6			(227.8	)
Prepaid and other current assets		(74.6	)		(6.3	)		(12.6	)
Other assets		18.7			2.4			(39.6	)
Increase (decrease) in:
Accounts payable – trade		(141.0	)		(10.1	)		34.1
Accounts payable – related parties		(31.6	)		23.6			(84.3	)
Accrued product payables		(1,647.8	)		1,043.8			(422.5	)
Accrued interest		31.3			3.5			12.7
Other current liabilities		141.3			(35.1	)		(14.4	)
Other liabilities		11.9			(18.2	)		(24.9	)
Net effect of changes in operating accounts	$	(108.2	)	$	(97.6	)	$	(582.5	)

Cash payments for interest, net of $77.9, $133.0 and $116.8 capitalized in 2014, 2013 and 2012, respectively	$	832.1		$	781.5		$	757.3

Cash payments for federal and state income taxes	$	16.1		$	35.0		$	44.8

Schedule of Significant Acquisitions and Disposals

The following table presents our cash proceeds from asset sales and insurance recoveries for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Sale of Energy Transfer Equity common units (see Note 9)	$	--	$	--	$	1,095.3
Sale of Stratton Ridge-to-Mont Belvieu segment of Seminole Pipeline (see Note 8)		--		86.9		--
Sales of pipeline line fill		27.5		65.0		--
Sale of lubrication oil and specialty chemical distribution assets		--		35.3		--
Sale of chemical trucking assets		--		29.5		--
Insurance recoveries attributable to West Storage claims (see Note 19)		95.0		15.0		30.0
Other cash proceeds		22.8		48.9		73.5
Total	$	145.3	$	280.6	$	1,198.8

The following table presents net gains (losses) attributable to asset sales and insurance recoveries for the periods indicated:

	For the Year Ended December 31,
	2014		2013		2012
Sale of Energy Transfer Equity common units (see Note 9)	$	--	$	--	$	68.8
Sale of Stratton Ridge-to-Mont Belvieu segment of Seminole Pipeline (see Note 8)		--		52.5		--
Net gains (losses) attributable to other asset sales		7.1		15.8		(12.4	)
Gains attributable to insurance recoveries (see Note 19)		95.0		15.0		30.0
Total	$	102.1	$	83.3	$	86.4

Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information (Unaudited) [Abstract]

Quarterly Financial Information (Unaudited)

The following table presents selected quarterly financial data for the periods indicated:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
For the Year Ended December 31, 2014:
Revenues	$	12,909.9	$	12,520.8	$	12,330.2	$	10,190.3
Operating income		1,032.7		884.3		937.7		921.0
Net income		806.7		646.5		699.2		681.1
Net income attributable to limited partners		798.8		637.7		691.1		659.8

Earnings per unit:
Basic	$	0.44	$	0.35	$	0.38	$	0.35
Diluted	$	0.43	$	0.34	$	0.37	$	0.34

For the Year Ended December 31, 2013:
Revenues	$	11,383.1	$	11,149.3	$	12,093.3	$	13,101.3
Operating income		957.7		774.2		819.9		915.5
Net income		755.3		553.3		592.8		705.7
Net income attributable to limited partners		753.5		552.5		592.0		698.9

Earnings per unit:
Basic	$	0.43	$	0.31	$	0.33	$	0.38
Diluted	$	0.41	$	0.30	$	0.32	$	0.37

Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2014

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2014

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	18.7	$	70.4	$	(14.7	)	$	74.4	$	--	$	--		$	74.4
Accounts receivable – trade, net		1,128.5		2,698.2		(3.7	)		3,823.0		--		--			3,823.0
Accounts receivable – related parties		158.8		1,114.6		(1,266.6	)		6.8		--		(4.0	)		2.8
Inventories		831.8		182.8		(0.4	)		1,014.2		--		--			1,014.2
Prepaid and other current assets		537.7		346.3		(308.5	)		575.5		--		0.8			576.3
Total current assets		2,675.5		4,412.3		(1,593.9	)		5,493.9		--		(3.2	)		5,490.7
Property, plant and equipment, net		2,871.7		26,912.0		97.9			29,881.6		--		--			29,881.6
Investments in unconsolidated affiliates		36,937.5		3,556.4		(37,451.9	)		3,042.0		18,187.2		(18,187.2	)		3,042.0
Intangible assets, net		2,527.3		1,292.4		482.4			4,302.1		--		--			4,302.1
Goodwill		1,956.1		1,621.1		622.7			4,199.9		--		--			4,199.9
Other assets		139.3		45.8		(0.7	)		184.4		--		--			184.4
Total assets	$	47,107.4	$	37,840.0	$	(37,843.5	)	$	47,103.9	$	18,187.2	$	(18,190.4	)	$	47,100.7

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	2,206.4	$	--	$	--		$	2,206.4	$	--	$	--		$	2,206.4
Accounts payable – trade		216.6		571.4		(14.8	)		773.2		0.6		--			773.8
Accounts payable – related parties		1,226.5		173.3		(1,280.9	)		118.9		4.0		(4.0	)		118.9
Accrued product payables		1,570.0		2,287.9		(4.6	)		3,853.3		--		--			3,853.3
Accrued interest		335.4		0.7		(0.6	)		335.5		--		--			335.5
Other current liabilities		130.8		763.7		(308.7	)		585.8		--		--			585.8
Total current liabilities		5,685.7		3,797.0		(1,609.6	)		7,873.1		4.6		(4.0	)		7,873.7
Long-term debt		19,142.5		14.9		--			19,157.4		--		--			19,157.4
Deferred tax liabilities		4.9		58.5		(0.9	)		62.5		--		4.1			66.6
Other long-term liabilities		10.9		180.8		(0.3	)		191.4		119.4		--			310.8
Commitments and contingencies		--
Equity:
Partners' and other owners' equity		22,263.4		33,720.6		(37,820.6	)		18,163.4		18,063.2		(18,163.4	)		18,063.2
Noncontrolling interests		--		68.2		1,587.9			1,656.1		--		(27.1	)		1,629.0
Total equity		22,263.4		33,788.8		(36,232.7	)		19,819.5		18,063.2		(18,190.5	)		19,692.2
Total liabilities and equity	$	47,107.4	$	37,840.0	$	(37,843.5	)	$	47,103.9	$	18,187.2	$	(18,190.4	)	$	47,100.7

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2013

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)		Other Subsidiaries (Non- guarantor)		EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries		Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
ASSETS
Current assets:
Cash and cash equivalents and restricted cash	$	93.9	$	49.5	$	(20.9	)	$	122.5	$	--	$	--		$	122.5
Accounts receivable – trade, net		1,986.8		3,491.1		(2.4	)		5,475.5		--		--			5,475.5
Accounts receivable – related parties		384.7		1,348.1		(1,726.0	)		6.8		0.2		(0.2	)		6.8
Inventories		948.5		145.4		(0.8	)		1,093.1		--		--			1,093.1
Prepaid and other current assets		140.9		191.4		(6.8	)		325.5		--		--			325.5
Total current assets		3,554.8		5,225.5		(1,756.9	)		7,023.4		0.2		(0.2	)		7,023.4
Property, plant and equipment, net		1,945.0		24,999.7		1.9			26,946.6		--		--			26,946.6
Investments in unconsolidated affiliates		30,819.9		2,921.2		(31,304.0	)		2,437.1		15,214.5		(15,214.5	)		2,437.1
Intangible assets, net		76.9		1,385.3		--			1,462.2		--		--			1,462.2
Goodwill		458.9		1,621.1		--			2,080.0		--		--			2,080.0
Other assets		123.5		67.2		(1.4	)		189.3		0.1		--			189.4
Total assets	$	36,979.0	$	36,220.0	$	(33,060.4	)	$	40,138.6	$	15,214.8	$	(15,214.7	)	$	40,138.7

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt	$	1,125.0	$	--	$	--		$	1,125.0	$	--	$	--		$	1,125.0
Accounts payable – trade		103.0		641.6		(20.9	)		723.7		--		--			723.7
Accounts payable – related parties		1,541.8		333.8		(1,724.9	)		150.7		--		(0.2	)		150.5
Accrued product payables		2,388.6		3,224.5		(4.4	)		5,608.7		--		--			5,608.7
Accrued interest		304.2		0.1		--			304.3		--		--			304.3
Other current liabilities		92.3		242.4		(6.7	)		328.0		--		(1.5	)		326.5
Total current liabilities		5,554.9		4,442.4		(1,756.9	)		8,240.4		--		(1.7	)		8,238.7
Long-term debt		16,211.6		14.9		--			16,226.5		--		--			16,226.5
Deferred tax liabilities		4.3		55.0		(1.4	)		57.9		--		2.9			60.8
Other long-term liabilities		11.8		160.5		--			172.3		--		--			172.3
Commitments and contingencies
Equity:
Partners' and other owners' equity		15,196.4		31,475.9		(31,482.4	)		15,189.9		15,214.8		(15,189.9	)		15,214.8
Noncontrolling interests		--		71.3		180.3			251.6		--		(26.0	)		225.6
Total equity		15,196.4		31,547.2		(31,302.1	)		15,441.5		15,214.8		(15,215.9	)		15,440.4
Total liabilities and equity	$	36,979.0	$	36,220.0	$	(33,060.4	)	$	40,138.6	$	15,214.8	$	(15,214.7	)	$	40,138.7

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2014

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	32,468.5		$	32,488.2		$	(17,005.5	)	$	47,951.2		$	--	$	--		$	47,951.2
Costs and expenses:
Operating costs and expenses		31,579.2			29,647.6			(17,006.3	)		44,220.5			--		--			44,220.5
General and administrative costs		39.1			173.2			--			212.3			2.2		--			214.5
Total costs and expenses		31,618.3			29,820.8			(17,006.3	)		44,432.8			2.2		--			44,435.0
Equity in income of unconsolidated affiliates		2,865.2			354.3			(2,960.0	)		259.5			2,789.6		(2,789.6	)		259.5
Operating income		3,715.4			3,021.7			(2,959.2	)		3,777.9			2,787.4		(2,789.6	)		3,775.7
Other income (expense):
Interest expense		(921.3	)		(2.5	)		2.8			(921.0	)		--		--			(921.0	)
Other, net		3.4			1.3			(2.8	)		1.9			--		--			1.9
Total other expense, net		(917.9	)		(1.2	)		--			(919.1	)		--		--			(919.1	)
Income before income taxes		2,797.5			3,020.5			(2,959.2	)		2,858.8			2,787.4		(2,789.6	)		2,856.6
Provision for income taxes		(11.5	)		(9.8	)		0.2			(21.1	)		--		(2.0	)		(23.1	)
Net income		2,786.0			3,010.7			(2,959.0	)		2,837.7			2,787.4		(2,791.6	)		2,833.5
Net loss (income) attributable to noncontrolling interests		--			0.4			(51.5	)		(51.1	)		--		5.0			(46.1	)
Net income attributable to entity	$	2,786.0		$	3,011.1		$	(3,010.5	)	$	2,786.6		$	2,787.4	$	(2,786.6	)	$	2,787.4

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2013

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	30,007.4		$	31,641.3		$	(13,921.7	)	$	47,727.0		$	--	$	--		$	47,727.0
Costs and expenses:
Operating costs and expenses		29,176.7			28,983.7			(13,921.7	)		44,238.7			--		--			44,238.7
General and administrative costs		29.1			157.0			--			186.1			2.2		--			188.3
Total costs and expenses		29,205.8			29,140.7			(13,921.7	)		44,424.8			2.2		--			44,427.0
Equity in income of unconsolidated affiliates		2,609.0			204.8			(2,646.5	)		167.3			2,599.1		(2,599.1	)		167.3
Operating income		3,410.6			2,705.4			(2,646.5	)		3,469.5			2,596.9		(2,599.1	)		3,467.3
Other income (expense):
Interest expense		(800.8	)		(1.7	)		--			(802.5	)		--		--			(802.5	)
Other, net		0.3			(0.5	)		--			(0.2	)		--		--			(0.2	)
Total other expense, net		(800.5	)		(2.2	)		--			(802.7	)		--		--			(802.7	)
Income before income taxes		2,610.1			2,703.2			(2,646.5	)		2,666.8			2,596.9		(2,599.1	)		2,664.6
Provision for income taxes		(13.9	)		(42.6	)		--			(56.5	)		--		(1.0	)		(57.5	)
Net income		2,596.2			2,660.6			(2,646.5	)		2,610.3			2,596.9		(2,600.1	)		2,607.1
Net loss (income) attributable to noncontrolling interests		--			(1.2	)		(12.9	)		(14.1	)		--		3.9			(10.2	)
Net income attributable to entity	$	2,596.2		$	2,659.4		$	(2,659.4	)	$	2,596.2		$	2,596.9	$	(2,596.2	)	$	2,596.9

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)		Eliminations and Adjustments			Consolidated Total
Revenues	$	29,654.7		$	28,221.5		$	(15,293.1	)	$	42,583.1		$	--	$	--		$	42,583.1
Costs and expenses:
Operating costs and expenses		28,839.1			25,821.8			(15,293.0	)		39,367.9			--		--			39,367.9
General and administrative costs		26.1			142.7			--			168.8			1.5		--			170.3
Total costs and expenses		28,865.2			25,964.5			(15,293.0	)		39,536.7			1.5		--			39,538.2
Equity in income of unconsolidated affiliates		2,381.8			80.7			(2,398.2	)		64.3			2,421.4		(2,421.4	)		64.3
Operating income		3,171.3			2,337.7			(2,398.3	)		3,110.7			2,419.9		(2,421.4	)		3,109.2
Other income (expense):
Interest expense		(767.1	)		(4.7	)		--			(771.8	)		--		--			(771.8	)
Other, net		0.1			73.3			--			73.4			--		--			73.4
Total other expense, net		(767.0	)		68.6			--			(698.4	)		--		--			(698.4	)
Income before income taxes		2,404.3			2,406.3			(2,398.3	)		2,412.3			2,419.9		(2,421.4	)		2,410.8
Provision for income taxes		15.7			2.4			--			18.1			--		(0.9	)		17.2
Net income		2,420.0			2,408.7			(2,398.3	)		2,430.4			2,419.9		(2,422.3	)		2,428.0
Net loss (income) attributable to noncontrolling interests		--			(5.1	)		(5.3	)		(10.4	)		--		2.3			(8.1	)
Net income attributable to entity	$	2,420.0		$	2,403.6		$	(2,403.6	)	$	2,420.0		$	2,419.9	$	(2,420.0	)	$	2,419.9

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2014

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments				Consolidated EPO and Subsidiaries				Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments				Consolidated Total
Comprehensive income		$	2,856.4		$	3,057.6		$	(2,958.9	)		$	2,955.1			$	2,904.8		$	(2,909.0	)		$	2,950.9
Comprehensive loss (income) attributable to noncontrolling interests			--			0.4			(51.5	)			(51.1	)			--			5.0				(46.1	)
Comprehensive income attributable to entity		$	2,856.4		$	3,058.0		$	(3,010.4	)		$	2,904.0			$	2,904.8		$	(2,904.0	) )		$	2,904.8

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2013

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)				EPO and Subsidiaries Eliminations and Adjustments				Consolidated EPO and Subsidiaries				Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments				Consolidated Total
Comprehensive income		$	2,616.5		$	2,651.6			$	(2,646.5	)		$	2,621.6			$	2,608.3		$	(2,611.4	)		$	2,618.5
Comprehensive income attributable to noncontrolling interests			--			(1.2	)			(12.9	)			(14.1	)			--			3.9				(10.2	)
Comprehensive income attributable to entity		$	2,616.5		$	2,650.4			$	(2,659.4	)		$	2,607.5			$	2,608.3		$	(2,607.5	)		$	2,608.3

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)				EPO and Subsidiaries Eliminations and Adjustments				Consolidated EPO and Subsidiaries				Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments				Consolidated Total
Comprehensive income		$	2,375.8		$	2,433.9			$	(2,398.3	)		$	2,411.4			$	2,400.9		$	(2,403.3	)		$	2,409.0
Comprehensive income attributable to noncontrolling interests			--			(5.1	)			(5.3	)			(10.4	)			--			2.3				(8.1	)
Comprehensive income attributable to entity		$	2,375.8		$	2,428.8			$	(2,403.6	)		$	2,401.0			$	2,400.9		$	(2,401.0	) )		$	2,400.9

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2014

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,786.0		$	3,010.7		$	(2,959.0	)	$	2,837.7		$	2,787.4		$	(2,791.6	)	$	2,833.5
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		153.0			1,208.0			(0.5	)		1,360.5			--			--			1,360.5
Equity in income of unconsolidated affiliates		(2,865.2	)		(354.3	)		2,960.0			(259.5	)		(2,789.6	)		2,789.6			(259.5	)
Distributions received from unconsolidated affiliates		4,539.9			327.1			(4,491.9	)		375.1			2,702.9			(2,702.9	)		375.1
Net effect of changes in operating accounts and other operating activities		(627.0	)		479.4			5.7			(141.9	)		(7.5	)		2.0			(147.4	)
Net cash flows provided by operating activities		3,986.7			4,670.9			(4,485.7	)		4,171.9			2,693.2			(2,702.9	)		4,162.2
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(647.9	)		(2,216.1	)		--			(2,864.0	)		--			--			(2,864.0	)
Cash used for business combinations, net of cash received		(2,437.5	)		20.7			--			(2,416.8	)		--			--			(2,416.8	)
Proceeds from asset sales and insurance recoveries		4.3			141.0			--			145.3			--			--			145.3
Other investing activities		(2,603.4	)		(660.0	)		2,601.0			(662.4	)		(384.6	)		384.6			(662.4	)
Cash used in investing activities		(5,684.5	)		(2,714.4	)		2,601.0			(5,797.9	)		(384.6	)		384.6			(5,797.9	)
Financing activities:
Borrowings under debt agreements		18,361.1			--			--			18,361.1			--			--			18,361.1
Repayments of debt		(14,341.1	)		--			--			(14,341.1	)		--			--			(14,341.1	)
Cash distributions paid to partners		(2,702.9	)		(4,537.8	)		4,537.8			(2,702.9	)		(2,638.1	)		2,702.9			(2,638.1	)
Cash payments made in connection with DERs		--			--			--			--			(3.7	)		--			(3.7	)
Cash distributions paid to noncontrolling interests		--			(2.7	)		(45.9	)		(48.6	)		--			--			(48.6	)
Cash contributions from noncontrolling interests		--			--			4.0			4.0			--			--			4.0
Net cash proceeds from issuance of common units		--			--			--			--			388.8			--			388.8
Cash contributions from owners		384.6			2,604.9			(2,604.9	)		384.6			--			(384.6	)		--
Other financing activities		(13.6	)		--			--			(13.6	)		(55.6	)		--			(69.2	)
Cash provided by (used in) financing activities		1,688.1			(1,935.6	)		1,891.0			1,643.5			(2,308.6	)		2,318.3			1,653.2
Net change in cash and cash equivalents		(9.7	)		20.9			6.3			17.5			--			--			17.5
Cash and cash equivalents, January 1		28.4			49.5			(21.0	)		56.9			--			--			56.9
Cash and cash equivalents, December 31	$	18.7		$	70.4		$	(14.7	)	$	74.4		$	--		$	--		$	74.4

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2013

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,596.2		$	2,660.6		$	(2,646.5	)	$	2,610.3		$	2,596.9		$	(2,600.1	)	$	2,607.1
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		143.5			1,072.8			1.3			1,217.6			--			--			1,217.6
Equity in income of unconsolidated affiliates		(2,609.0	)		(204.8	)		2,646.5			(167.3	)		(2,599.1	)		2,599.1			(167.3	)
Distributions received from unconsolidated affiliates		4,523.2			233.7			(4,505.3	)		251.6			2,454.4			(2,454.4	)		251.6
Net effect of changes in operating accounts and other operating activities		(1,351.0	)		1,323.4			(10.1	)		(37.7	)		(7.8	)		2.0			(43.5	)
Net cash flows provided by operating activities		3,302.9			5,085.7			(4,514.1	)		3,874.5			2,444.4			(2,453.4	)		3,865.5
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(517.8	)		(2,864.4	)		--			(3,382.2	)		--			--			(3,382.2	)
Proceeds from asset sales and insurance recoveries		59.6			221.0			--			280.6			--			--			280.6
Other investing activities		(3,163.6	)		(769.5	)		2,777.2			(1,155.9	)		(1,791.1	)		1,791.1			(1,155.9	)
Cash used in investing activities		(3,621.8	)		(3,412.9	)		2,777.2			(4,257.5	)		(1,791.1	)		1,791.1			(4,257.5	)
Financing activities:
Borrowings under debt agreements		13,852.8			--			--			13,852.8			--			--			13,852.8
Repayments of debt		(12,650.8	)		(29.8	)		--			(12,680.6	)		--			--			(12,680.6	)
Cash distributions paid to partners		(2,453.4	)		(4,514.1	)		4,514.1			(2,453.4	)		(2,400.4	)		2,453.5			(2,400.3	)
Cash distributions paid to noncontrolling interests		--			--			(8.9	)		(8.9	)		--			--			(8.9	)
Cash contributions from noncontrolling interests		--			--			115.4			115.4			--			--			115.4
Net cash proceeds from issuance of common units		--			--			--			--			1,792.0			--			1,792.0
Cash contributions from owners		1,791.2			2,892.6			(2,892.6	)		1,791.2			--			(1,791.2	)		--
Other financing activities		(192.5	)		--			--			(192.5	)		(45.1	)		--			(237.6	)
Cash provided by (used in) financing activities		347.3			(1,651.3	)		1,728.0			424.0			(653.5	)		662.3			432.8
Net change in cash and cash equivalents		28.4			21.5			(8.9	)		41.0			(0.2	)		--			40.8
Cash and cash equivalents, January 1		--			28.0			(12.1	)		15.9			0.2			--			16.1
Cash and cash equivalents, December 31	$	28.4		$	49.5		$	(21.0	)	$	56.9		$	--		$	--		$	56.9

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2012

	EPO and Subsidiaries
	Subsidiary Issuer (EPO)			Other Subsidiaries (Non- guarantor)			EPO and Subsidiaries Eliminations and Adjustments			Consolidated EPO and Subsidiaries			Enterprise Products Partners L.P. (Guarantor)			Eliminations and Adjustments			Consolidated Total
Operating activities:
Net income	$	2,420.0		$	2,408.7		$	(2,398.3	)	$	2,430.4		$	2,419.9		$	(2,422.3	)	$	2,428.0
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		118.0			986.9			--			1,104.9			--			--			1,104.9
Equity in income of unconsolidated affiliates		(2,381.8	)		(80.7	)		2,398.2			(64.3	)		(2,421.4	)		2,421.4			(64.3	)
Distributions received from unconsolidated affiliates		3,918.9			106.6			(3,908.8	)		116.7			2,209.3			(2,209.3	)		116.7
Net effect of changes in operating accounts and other operating activities		(2,174.9	)		1,485.3			(0.8	)		(690.4	)		(4.9	)		0.9			(694.4	)
Net cash flows provided by operating activities		1,900.2			4,906.8			(3,909.7	)		2,897.3			2,202.9			(2,209.3	)		2,890.9
Investing activities:
Capital expenditures, net of contributions in aid of construction costs		(219.5	)		(3,379.0	)		--			(3,598.5	)		--			--			(3,598.5	)
Proceeds from asset sales and insurance recoveries		1,137.2			61.6			--			1,198.8			--			--			1,198.8
Other investing activities		(2,961.4	)		(432.3	)		2,774.6			(619.1	)		(816.2	)		816.2			(619.1	)
Cash used in investing activities		(2,043.7	)		(3,749.7	)		2,774.6			(3,018.8	)		(816.2	)		816.2			(3,018.8	)
Financing activities:
Borrowings under debt agreements		8,363.1			--			--			8,363.1			--			--			8,363.1
Repayments of debt		(6,666.9	)		(9.5	)		--			(6,676.4	)		--			--			(6,676.4	)
Cash distributions paid to partners		(2,209.3	)		(3,922.1	)		3,922.1			(2,209.3	)		(2,178.6	)		2,209.3			(2,178.6	)
Cash distributions paid to noncontrolling interests		--			--			(13.3	)		(13.3	)		--			--			(13.3	)
Cash contributions from noncontrolling interests		--			--			6.6			6.6			--			--			6.6
Net cash proceeds from issuance of common units		--			--			--			--			816.8			--			816.8
Cash contributions from owners		816.2			2,781.2			(2,781.2	)		816.2			--			(816.2	)		--
Other financing activities		(169.3	)		--			--			(169.3	)		(24.7	)		--			(194.0	)
Cash provided by (used in) financing activities		133.8			(1,150.4	)		1,134.2			117.6			(1,386.5	)		1,393.1			124.2
Net change in cash and cash equivalents		(9.7	)		6.7			(0.9	)		(3.9	)		0.2			--			(3.7	)
Cash and cash equivalents, January 1		9.7			21.3			(11.2	)		19.8			--			--			19.8
Cash and cash equivalents, December 31	$	--		$	28.0		$	(12.1	)	$	15.9		$	0.2		$	--		$	16.1

Partnership Operations, Organization and Basis of Presentation (Details) bbl in Millions, ft³ in Billions	3 Months Ended	12 Months Ended
	Dec. 31, 2014 Plant Fractionator Platform mi shares bbl ft³	Dec. 31, 2014 Plant Fractionator Platform Segment mi bbl ft³	Oct. 02, 2014 bbl
Partnership Operations, Organization and Basis of Presentation [Abstract]
Number of miles of onshore and offshore pipelines \| mi	51,300	51,300
Number of barrels of storage capacity \| bbl	225	225
Number of cubic feet of storage capacity \| ft³	14	14
Number of natural gas processing plants \| Plant	24	24
Number of fractionators \| Fractionator	22	22
Number of offshore hub platforms \| Platform	6	6
Number of reportable segments \| Segment		5
Limited partners ownership interest (in hundredths)		100.00%
Oiltanking Partners L.P. [Member]
Partnership Operations, Organization and Basis of Presentation [Abstract]
Number of barrels of storage capacity \| bbl			26
Business Acquisition [Line Items]
Common units acquired (in units) \| shares	15,899,802
Subordinated units acquired (in units) \| shares	38,899,802

Summary of Significant Accounting Policies (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Current Assets and Current Liabilities [Abstract]

Threshold for components of total current assets and liabilities to be presented as an individual caption on Consolidated Balance Sheet (in hundredths)

5.00%

Environmental Costs [Abstract]

Environmental reserves - current portion

$ 8.1

$ 6.0

Other Non-operating Income [Abstract]

Gain on sales of available-for-sale securities of Energy Transfer Equity

^[1]

0.0

$ 68.8

Other

0.6

(1.1)

3.8

Total

0.6

(1.1)

72.6

Restricted Cash [Abstract]

Restricted cash

0.0

65.6

Allowance for Doubtful Accounts, Current [Member]

Movement in valuation allowances and reserves [Roll Forward]

Balance at beginning of period

7.5

13.2

13.4

Charged to costs and expenses

8.4

2.1

0.3

Deductions

^[2]

(2.0)

(7.8)

(0.5)

Balance at end of period

13.9

7.5

13.2

Reserve for Environmental Costs [Member]

Movement in valuation allowances and reserves [Roll Forward]

Balance at beginning of period

9.9

13.7

12.3

Charged to costs and expenses

11.9

3.9

13.9

Acquisition-related additions and other

2.5

0.7

5.2

Deductions

(8.7)

(8.4)

(17.7)

Balance at end of period

$ 15.6

$ 9.9

$ 13.7

Minor Investment [Member] | Maximum [Member]

Equity method of ownership interest (in hundredths)

50.00%

Minor Investment [Member] | Minimum [Member]

Equity method of ownership interest (in hundredths)

3.00%

Major Investment [Member] | Maximum [Member]

Equity method of ownership interest (in hundredths)

50.00%

Major Investment [Member] | Minimum [Member]

Equity method of ownership interest (in hundredths)

20.00%

[1]	See Note 9 for information regarding the liquidation of our investment in limited partnership units of Energy Transfer Equity.
[2]	The 2013 deduction is primarily due to the write-off of certain amounts attributable to companies in bankruptcy and amounts we believe are no longer collectible.

Equity-based Awards (Details) - USD ($) $ in Millions	12 Months Ended
Equity-based Awards (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity-based compensation expense [Abstract]
Total compensation expense	$ 87.5	$ 72.8	$ 60.0
Equity-classified awards [Member] \| Restricted Common Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	42.1	71.5	57.0
Equity-classified awards [Member] \| Unit Option Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	0.0	0.8	1.3
Equity-classified awards [Member] \| Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	45.1	0.0	0.0
Liability-classified awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 0.3	$ 0.5	$ 1.7
Long-Term Incentive Plan (1998) [Member]
Equity-based compensation expense [Abstract]
Maximum number of common units that may be issued as awards (in units)	14,000,000
Remaining number of common units available to be issued as awards (in units)	2,748,017
Long-Term Incentive Plan (2008) [Member]
Equity-based compensation expense [Abstract]
Incremental number of units to be authorized annually (in units)	5,000,000
Maximum number of additional units to be authorized for issuance (in units)	70,000,000
Maximum number of common units that may be issued as awards (in units)	25,000,000
Remaining number of common units available to be issued as awards (in units)	12,895,605

Equity-based Awards, Restricted Unit Awards (Details) - Restricted Common Unit Awards [Member] - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Vesting rate of restricted common unit awards (in hundredths)

25.00%

Summary of awards activity, equity instruments other than options [Roll Forward]

Beginning of period (in units)

7,221,214

7,786,972

7,736,432

Granted (in units)

3,549,052

^[1]

3,177,476

^[2]

Vested (in units)

(2,634,074)

(3,770,696)

(2,633,206)

Forfeited (in units)

(357,350)

(344,114)

(493,730)

End of period (in units)

4,229,790

7,221,214

7,786,972

Restricted units outstanding, weighted-average grant date fair value [Roll Forward]

Weighted-average grant date fair value per unit, at beginning of period (in dollars per unit)

^[3]

$ 25.83

$ 20.43

$ 17.11

Granted weighted-average grant date fair value per unit (in dollars per unit)

^[3]

28.61

^[1]

25.98

^[2]

Vested weighted-average grant date fair value per unit (in dollars per unit)

^[3]

23.94

17.48

17.40

Forfeited weighted-average grant date fair value per unit (in dollars per unit)

^[3]

26.38

23.82

20.21

Weighted-average grant date fair value per unit, at end of period (in dollars per unit)

^[3]

$ 26.96

$ 25.83

$ 20.43

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Aggregate grant date fair value

$ 101.5

$ 82.5

Estimated forfeiture rate (in hundredths)

3.90%

3.25%

Cash distributions paid to restricted common unitholders

$ 7.3

$ 10.6

$ 10.5

Total intrinsic value of restricted common unit awards that vested during period

87.1

$ 109.9

$ 67.0

Recognition period for total unrecognized compensation cost

$ 28.3

1 year 6 months

Minimum [Member]

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Grant date market price of common units (in dollars per unit)

$ 28.56

$ 25.96

Maximum [Member]

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Grant date market price of common units (in dollars per unit)

$ 31.74

$ 26.77

Enterprise [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 24.9

[1]	The aggregate grant date fair value of restricted common unit awards issued during 2013 was $101.5 million based on a grant date market price of our common units ranging from $28.56 to $31.74 per unit. An estimated annual forfeiture rate of 3.9% was applied to these awards.
[2]	The aggregate grant date fair value of restricted common unit awards issued during 2012 was $82.5 million based on a grant date market price of our common units ranging from $25.96 to $26.77 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards.
[3]	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Equity-based Awards, Unit Option Awards (Details) - Unit Option Awards [Member] - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Vesting period

4 years

Summary of awards activity, options [Roll Forward]

Beginning of period (in units)

4,050,000

^[1],[2]

5,522,280

7,506,840

Exercised (in units)

(2,720,000)

(1,472,280)

(1,484,560)

Forfeited (in units)

(60,000)

(500,000)

End of period (in units)

1,270,000

^[1],[2]

4,050,000

^[1],[2]

5,522,280

Options outstanding, weighted-average strike price [Roll Forward]

Weighted average strike price, beginning of period (in dollars per unit)

$ 13.24

^[1],[2]

$ 13.71

$ 14.04

Weighted average strike price, exercised (in dollars per unit)

11.83

14.98

15.39

Weighted average strike price, forfeited (in dollars per unit)

16.14

13.73

Weighted average strike price, end of period (in dollars per unit)

$ 16.14

^[1],[2]

$ 13.24

^[1],[2]

$ 13.71

Weighted average remaining contractual term

^[1],[2]

1 year

Aggregate intrinsic value

^[1],[2],[3]

$ 25.4

Total intrinsic value of unit option awards exercised during period

57.5

$ 19.8

$ 14.6

Cash received from EPCO in connection with the exercise of unit option awards

33.4

11.5

10.2

$ 57.5

$ 19.8

$ 14.0

[1]	At December 31, 2014 and 2013, we were committed to issue 1,270,000 and 4,050,000, respectively, of our common units if all outstanding unit option awards were exercised. All of the unit option awards outstanding at December 31, 2014 vested during 2014 and became exercisable beginning in February 2015.
[2]	None of the unit option awards outstanding at December 31, 2014, 2013 and 2012 were exercisable as of such dates, respectively.
[3]	Aggregate intrinsic value reflects fully vested unit option awards at the date indicated.

Equity-based Awards, Phantom Unit Awards (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Cash payments made in connection with DERs

$ 3.7

$ 0.0

Phantom Unit Awards [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Vesting rate of phantom unit awards (in hundredths)

25.00%

Summary of awards activity, equity instruments other than options [Roll Forward]

Beginning of period (in units)

Granted (in units)

^[1]

3,530,710

Vested (in units)

(38,200)

Forfeited (in units)

(150,120)

End of period (in units)

3,342,390

Phantom units outstanding, weighted-average grant date fair value [Roll Forward]

Weighted-average grant date fair value per unit, at beginning of period (in dollars per unit)

^[2]

$ 0

Granted weighted-average grant date fair value per unit (in dollars per unit)

^[1],[2]

33.12

Vested weighted-average grant date fair value per unit (in dollars per unit)

^[2]

33.04

Forfeited weighted-average grant date fair value per unit (in dollars per unit)

^[2]

33.12

Weighted-average grant date fair value per unit, at end of period (in dollars per unit)

^[2]

$ 33.13

$ 0

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Aggregate grant date fair value

$ 117.0

Estimated forfeiture rate (in hundredths)

3.40%

Cash payments made in connection with DERs

$ 3.7

$ 0.0

0.0

Total intrinsic value of phantom unit awards that vested during period

1.4

$ 0.0

Recognition period for total unrecognized compensation cost

$ 58.2

2 years 2 months 12 days

Phantom Unit Awards [Member] | Minimum [Member]

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Grant date market price of common units (in dollars per unit)

$ 33.04

Phantom Unit Awards [Member] | Maximum [Member]

Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]

Grant date market price of common units (in dollars per unit)

$ 37.59

Phantom Unit Awards [Member] | Enterprise [Member]

$ 53.1

[1]	The aggregate grant date fair value of phantom unit awards issued during 2014 was $117.0 million based on a grant date market price of our common units ranging from $33.04 to $37.59 per unit. An estimated annual forfeiture rate of 3.4% was applied to these awards.
[2]	Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Derivative Instruments, Hedging Activities and Fair Value Measurements (Details)
bbl in Millions, $ in Millions, ft³ in Billions

1 Months Ended

12 Months Ended

Oct. 31, 2014

USD ($)

Contract

Jul. 31, 2014

USD ($)

Contract

Dec. 31, 2014

bbl

ft³

Dec. 31, 2013

USD ($)

Contract

Dec. 31, 2012

USD ($)

Contract

Oct. 14, 2014

USD ($)

Minimum [Member]

Expected offset percentage of change in fair value derivative instrument (in hundredths)

80.00%

Maximum [Member]

Expected offset percentage of change in fair value derivative instrument (in hundredths)

125.00%

Interest rate derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Forward Starting Swaps [Member]

Number of derivative instruments settled | Contract

Notional amount of settled derivative instruments | $

$ 1,000.0

$ 850.0

Accumulated other comprehensive income (loss) related to interest rate derivative instruments | $

$ (168.8)

$ (185.5)

Interest rate derivatives [Member] | Derivatives in fair value hedging relationships [Member]

Loss (gain) recognized due to settlement of derivative instruments | $

$ (27.6)

Interest rate derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Senior Notes AA [Member]

Number of derivative instruments settled | Contract

Notional amount of settled derivative instruments | $

$ 750.0

Loss (gain) recognized due to settlement of derivative instruments | $

(17.6)

Interest rate derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Senior Notes LL [Member]

Number of derivative instruments settled | Contract

Notional amount of settled derivative instruments | $

$ 800.0

Loss (gain) recognized due to settlement of derivative instruments | $

$ (10.0)

Interest rate derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Interest Rate Swap [Member]

Number of derivative instruments settled | Contract

Notional amount of settled derivative instruments | $

$ 800.0

Loss (gain) recognized due to settlement of derivative instruments | $

$ (37.7)

Interest rate derivatives [Member] | Derivatives in mark-to-market relationships [Member] | Undesignated Swaps [Member]

Number of derivative instruments settled | Contract

Notional amount of settled derivative instruments | $

$ 600.0

Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Natural gas processing: Forecasted sales of NGLs [Member]

Forecasted NGL sales designated as normal sales agreements | bbl

^[1],[2],[3]

0.9

0.1

Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Natural gas marketing: Forecasted sales of natural gas [Member]

Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member]

Current Volume | ft³

^[2],[3]

1.0

Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member]

^[2],[3]

9.9

Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Refined products marketing: Forecasted purchases of refined products [Member]

^[2],[3]

10.2

Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Refined products marketing: Forecasted sales of refined products [Member]

^[2],[3]

1.2

Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member]

^[2],[3]

1.8

Commodity derivatives [Member] | Derivatives in cash flow hedging relationships [Member] | Crude oil marketing: Forecasted sales of crude oil [Member]

^[2],[3]

5.8

Commodity derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Natural gas marketing: Natural gas storage inventory management activities [Member]

^[2],[3]

6.9

Commodity derivatives [Member] | Derivatives in fair value hedging relationships [Member] | Refined products marketing: Refined products inventory management activities [Member]

Current Volume | ft³

^[2],[3]

8.6

Commodity derivatives [Member] | Derivatives in mark-to-market relationships [Member] | Natural gas risk management activities [Member]

^[2],[3]

0.2

Current natural gas hedging volumes designated as an index plus or minus a discount | ft³

Current Volume | ft³

^{[2],[3],[4],[5]}

81.4

Long Term Volume | ft³

^{[2],[3],[4],[5]}

11.8

35.2

Commodity derivatives [Member] | Derivatives in mark-to-market relationships [Member] | Crude oil risk management activities [Member]

Derivatives in fair value hedging relationships [Member]

^[2],[3],[5]

4.2

[1]	Forecasted sales of NGL volumes under natural gas processing exclude 0.1 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
[2]	The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2015, October 2015 and March 2018, respectively.
[3]	Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
[4]	Current volumes include 35.2 Bcf of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences.
[5]	Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Derivative Instruments, Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives		$ 32.6
Liability Derivatives		7.8
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 226.6	41.3
Liability Derivatives	147.4	55.1
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	217.9	63.5
Liability Derivatives	145.3	46.8
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.0	32.6
Liability Derivatives	0.0	0.0
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.0	20.2
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.0	12.4
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0.0	0.0
Derivatives designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0.0	0.0
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	217.9	30.9
Liability Derivatives	145.3	46.8
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	217.9	30.9
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.0	0.0
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	145.3	46.5
Derivatives designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0.0	0.3
Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	8.7	10.4
Liability Derivatives	2.1	16.1
Derivatives not designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.0	0.0
Derivatives not designated as hedging instruments [Member] \| Interest rate derivatives [Member] \| Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0.0	7.8
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	8.7	10.4
Liability Derivatives	2.1	8.3
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	8.1	7.6
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0.6	2.8
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0.7	5.5
Derivatives not designated as hedging instruments [Member] \| Commodity derivatives [Member] \| Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 1.4	$ 2.8

Derivative Instruments, Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Commodity derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 226.6	$ 41.3
Gross Amounts Offset in the Balance Sheet	0.0	0.0
Amounts of Assets Presented in the Balance Sheet	226.6	41.3
Financial Instruments	(147.3)	(41.0)
Cash Collateral Received	(23.9)	0.0
Amounts That Would Have Been Presented On Net Basis	$ 55.4	0.3
Interest rate derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets		32.6
Gross Amounts Offset in the Balance Sheet		0.0
Amounts of Assets Presented in the Balance Sheet		32.6
Financial Instruments		(2.6)
Cash Collateral Received		0.0
Amounts That Would Have Been Presented On Net Basis		$ 30.0

Derivative Instruments, Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Commodity derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 147.4	$ 55.1
Gross Amounts Offset in the Balance Sheet	0.0	0.0
Amounts of Liabilities Presented in the Balance Sheet	147.4	55.1
Financial Instruments	(147.3)	(41.0)
Cash Collateral Paid	0.0	(9.3)
Amounts That Would Have Been Presented On Net Basis	$ 0.1	4.8
Interest rate derivatives [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities		7.8
Gross Amounts Offset in the Balance Sheet		0.0
Amounts of Liabilities Presented in the Balance Sheet		7.8
Financial Instruments		(2.6)
Cash Collateral Paid		0.0
Amounts That Would Have Been Presented On Net Basis		$ 5.2

Derivative Instruments, Hedging Activities and Fair Value Measurements, Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Hedged Item

$ (14.6)

$ (13.2)

$ (3.7)

14.6

7.1

16.2

Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member] | Location - Revenue [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Hedged Item

11.9

(0.1)

(6.4)

(11.8)

(5.7)

19.1

Derivatives in fair value hedging relationships [Member] | Interest rate derivatives [Member] | Location - Interest expense [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Recognized in Income on Hedged Item

(26.5)

(13.1)

2.7

26.4

12.8

(2.9)

Derivatives in cash flow hedging relationships [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion)

161.3

(40.3)

(52.9)

Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)

44.3

(51.3)

(30.4)

Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)

(0.3)

0.2

0.3

Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months

70.0

Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Location - Revenue [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion)

^[1]

161.3

(47.9)

31.0

Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)

75.0

(22.4)

10.1

Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)

(0.3)

0.2

0.0

Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Location - Operating costs and expenses [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion)

^[1]

0.0

1.0

(13.7)

Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)

1.7

0.3

(24.3)

Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)

0.0

0.3

Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion)

0.0

6.6

(70.2)

Accumulated other comprehensive loss related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months

(35.4)

Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member] | Location - Interest expense [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income (Effective Portion)

(32.4)

(29.2)

(16.2)

Derivatives not designated as hedging instruments [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Location - Revenue [Member]

(23.1)

6.6

14.3

Derivative Instruments, Gain (Loss) [Line Items]

Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Location - Operating costs and expenses [Member]

(23.0)

7.3

22.7

Derivative Instruments, Gain (Loss) [Line Items]

Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Location - Interest expense [Member]

0.0

(2.8)

Derivative Instruments, Gain (Loss) [Line Items]

$ (0.1)

$ (0.7)

$ (5.6)

[1]	The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations upon settlement of the underlying derivative transactions, as appropriate.

Derivative Instruments, Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities

$ 119.4

$ 0.0

Total gains (losses) included in:

(30.6)

(1.4)

$ 29.5

Fair Value, Measurements, Recurring [Member] | Level 3 [Member]

1.0

Reconciliation of changes in the fair value of Level 3 financial assets and liabilities [Roll Forward]

120.0

Financial asset (liability) balance, net, beginning of period

3.2

^[1]

(1.5)

Total gains (losses) included in:

Net income

^[2]

0.9

2.8

Other comprehensive income (loss)

(2.6)

(0.9)

Settlements

(3.4)

1.6

Acquisition of Liquidity Option Agreement

(119.4)

0.0

Transfers out of Level 3

^[1]

2.3

1.2

Financial asset (liability) balance, net, end of period

(119.0)

^[1]

3.2

^[1]

$ (1.5)

Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities

(2.6)

4.4

Fair Value, Measurements, Recurring [Member] | Fair Value [Member]

32.6

226.6

41.3

73.9

7.8

119.4

147.4

55.1

Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 1 [Member]

266.8

62.9

0.0

37.8

17.2

17.2

0.0

0.0

13.8

30.8

Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 2 [Member]

13.8

30.8

32.6

187.8

20.2

52.8

7.8

0.0

133.0

23.6

Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Level 3 [Member]

133.0

31.4

0.0

1.0

3.9

3.9

0.0

119.4

0.6

0.7

Available-for-Sale Inventory by Product Type [Abstract]

$ 120.0

$ 0.7

[1]	Transfers out of Level 3 into Level 2 were due to shorter remaining transaction maturities falling inside of the Level 2 range at December 31, 2014 and 2013.
[2]	There were $2.6 million and $4.4 million of unrealized losses and gains included in these amounts for the years ended December 31, 2014 and 2013, respectively.

Derivative Instruments, Hedging Activities and Fair Value Measurements, Level 3 Recurring Valuation Techniques (Details) - Level 3 [Member] $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($) $ / bbl $ / MMBTU	Dec. 31, 2013 USD ($) $ / bbl
Liability - Liquidity Option Agreement [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair Value Measurements, Valuation Techniques	Discounted cash flow
Input description	Expected life of OTA following option exercise, Estimated growth rates in Enterprise’s earnings before interest, taxes, depreciation and amortization, OTA ownership interest in Enterprise common units, Interest rate on assumed debt of OTA following option exercise, Forecasted yield on Enterprise common units, Federal and state tax rate
Fair value inputs, Expected life of OTA following option exercise (in years)	30
Fair value inputs, Interest rate on assumed debt of OTA following option exercise	4.9% over 30 years
Fair value inputs, federal and state tax rate (in hundredths)	38.00%
Liability - Liquidity Option Agreement [Member] \| Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization (in hundredths)	3.00%
Fair value inputs, OTA ownership interest in Enterprise common units (in hundredths)	1.90%
Fair value inputs, Forecasted yield on Enterprise common units (in hundredths)	4.00%
Liability - Liquidity Option Agreement [Member] \| Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization (in hundredths)	14.00%
Fair value inputs, OTA ownership interest in Enterprise common units (in hundredths)	2.80%
Fair value inputs, Forecasted yield on Enterprise common units (in hundredths)	5.50%
Asset commodity derivatives - Crude oil [Member] \| Liability commodity derivatives - Crude oil [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair Value Measurements, Valuation Techniques	Discounted cash flow
Input description	Forward commodity prices
Asset commodity derivatives - Crude oil [Member] \| Liability commodity derivatives - Crude oil [Member] \| Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) \| $ / bbl	49.26	89.55
Asset commodity derivatives - Crude oil [Member] \| Liability commodity derivatives - Crude oil [Member] \| Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) \| $ / bbl	53.27	98.54
Assets commodity derivatives - Natural gas [Member] \| Liability commodity derivatives - Natural gas [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair Value Measurements, Valuation Techniques	Discounted cash flow
Input description	Forward commodity prices
Assets commodity derivatives - Natural gas [Member] \| Liability commodity derivatives - Natural gas [Member] \| Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) \| $ / MMBTU	3.05
Assets commodity derivatives - Natural gas [Member] \| Liability commodity derivatives - Natural gas [Member] \| Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, forward commodity price (in dollars per unit) \| $ / MMBTU	4.09
Fair Value, Measurements, Recurring [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial assets	$ 1.0
Financial liabilities	120.0
Fair Value, Measurements, Recurring [Member] \| Liability commodity derivatives - Crude oil [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial liabilities	0.4	$ 0.7
Fair Value, Measurements, Recurring [Member] \| Liability commodity derivatives - Natural gas [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial liabilities	0.2
Fair Value, Measurements, Recurring [Member] \| Liability - Liquidity Option Agreement [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial liabilities	119.4
Fair Value, Measurements, Recurring [Member] \| Asset commodity derivatives - Crude oil [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial assets	1.0	$ 3.9
Fair Value, Measurements, Recurring [Member] \| Assets commodity derivatives - Natural gas [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Financial assets	$ 0.0

Derivative Instruments, Hedging Activities and Fair Value Measurements, Nonrecurring Fair Value Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	$ 34.0	$ 97.4	$ 63.4
Non-cash asset impairment charges in costs and expenses	34.0	92.6	63.4
Non-cash asset impairment charges of unconsolidated affiliate		4.8
NGL Pipelines and Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	16.2	30.6	16.3
Onshore Natural Gas Pipelines & Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	0.7	0.0	29.2
Onshore Crude Oil Pipelines and Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	2.9	30.1	10.6
Offshore Pipelines And Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	5.1	18.0	4.0
Petrochemical and Refined Products Services [Member]
Assets, Fair Value Disclosure [Abstract]
Non-cash asset impairment charges	9.1	18.7	3.3
Fair Value, Measurements, Nonrecurring [Member]
Assets, Fair Value Disclosure [Abstract]
Impairment of long-lived assets disposed of other than by sale	26.7	79.4	56.5
Impairment of long-lived assets held and used		9.0	2.6
Impairment of long-lived assets to be disposed of by sale	7.3	9.0	4.3
Fair Value, Measurements, Nonrecurring [Member] \| Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.8
Fair Value, Measurements, Nonrecurring [Member] \| Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		44.6	2.2
Fair Value, Measurements, Nonrecurring [Member] \| Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	1.5	0.6	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 1 [Member] \| Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 1 [Member] \| Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 1 [Member] \| Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 2 [Member] \| Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 2 [Member] \| Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 2 [Member] \| Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.0
Fair Value, Measurements, Nonrecurring [Member] \| Level 3 [Member] \| Long-lived Assets Disposed of Other Than By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	0.0	0.0	0.8
Fair Value, Measurements, Nonrecurring [Member] \| Level 3 [Member] \| Long-lived Assets Held and Used [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value		44.6	2.2
Fair Value, Measurements, Nonrecurring [Member] \| Level 3 [Member] \| Long-lived Assets Disposed of By Sale [Member]
Assets, Fair Value Disclosure [Abstract]
Assets, fair value	$ 1.5	$ 0.6	$ 0.0

Derivative Instruments, Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed Rate Debt Principal Amount Fair Value Disclosure	$ 20,480	$ 16,880
Level 2 [Member] \| Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed Rate Debt Principal Amount Fair Value Disclosure	$ 22,160	$ 17,930

Inventories (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

NGLs

$ 579.1

$ 593.8

Petrochemicals and refined products

295.6

395.1

Crude oil

97.8

42.6

Natural gas

41.7

61.6

Total

1,014.2

1,093.1

Summary of cost of sales and lower of cost or market adjustments [Abstract]

Cost of sales

^[1]

40,464.1

40,770.2

$ 36,015.5

Lower of cost or market adjustments

$ 22.8

$ 18.5

$ 22.1

[1]	Cost of sales is a component of "Operating costs and expenses," as presented on our Statements of Consolidated Operations. Year-to-year fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Oct. 02, 2014

Property, plant and equipment and accumulated depreciation [Abstract]

Less accumulated depreciation

$ 38,046.7

$ 34,017.6

8,165.1

7,071.0

Summary of depreciation expense and capitalized interest [Abstract]

29,881.6

26,946.6

$ 24,846.4

Depreciation expense

^[1]

1,114.1

1,012.4

900.5

Capitalized interest

^[2]

77.9

133.0

116.8

Asset Retirement Obligations [Roll Forward]

Balance at beginning of period

90.2

105.2

112.0

Liabilities incurred

0.1

1.7

Liabilities settled

(2.7)

(14.2)

(27.8)

Revisions in estimated cash flows

4.6

(8.6)

13.7

Accretion expense

6.1

5.6

Balance at end of period

98.3

90.2

$ 105.2

Capitalized costs, asset retirement costs

31.3

37.4

Forecasted accretion expense [Abstract]

6.2

6.4

6.9

7.5

7.6

Oiltanking Partners L.P. [Member]

Property, plant and equipment and accumulated depreciation [Abstract]

Plants, pipelines and facilities [Member]

$ 1,080.1

Property, plant and equipment and accumulated depreciation [Abstract]

Plants, pipelines and facilities [Member] | Oiltanking Partners L.P. [Member]

^[3]

$ 30,834.9

27,540.4

Property, plant and equipment and accumulated depreciation [Abstract]

Plants, pipelines and facilities [Member] | Minimum [Member]

395.6

Property, plant and equipment and accumulated depreciation [Abstract]

Plants, pipelines and facilities [Member] | Maximum [Member]

^[3],[4]

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member]

^[3],[4]

45 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member] | Oiltanking Partners L.P. [Member]

^[5]

$ 2,584.2

2,101.8

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member] | Minimum [Member]

407.3

Property, plant and equipment and accumulated depreciation [Abstract]

Underground and other storage facilities [Member] | Maximum [Member]

^[5],[6]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Platforms and facilities [Member]

^[5],[6]

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

Platforms and facilities [Member] | Minimum [Member]

^[7]

$ 659.7

659.6

Property, plant and equipment and accumulated depreciation [Abstract]

Platforms and facilities [Member] | Maximum [Member]

^[7]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member]

^[7]

31 years

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member] | Minimum [Member]

^[8]

$ 154.2

138.9

Property, plant and equipment and accumulated depreciation [Abstract]

Transportation equipment [Member] | Maximum [Member]

^[8]

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment and accumulated depreciation [Abstract]

^[8]

10 years

Marine vessels [Member]

Marine vessels [Member] | Minimum [Member]

^[9]

$ 796.4

744.8

Property, plant and equipment and accumulated depreciation [Abstract]

Marine vessels [Member] | Maximum [Member]

^[9]

15 years

Property, plant and equipment and accumulated depreciation [Abstract]

Property, plant and equipment and accumulated depreciation [Abstract]

^[9]

30 years

Land [Member]

Land [Member] | Oiltanking Partners L.P. [Member]

$ 262.6

176.6

Property, plant and equipment and accumulated depreciation [Abstract]

Construction in progress [Member]

76.3

Property, plant and equipment and accumulated depreciation [Abstract]

Construction in progress [Member] | Oiltanking Partners L.P. [Member]

$ 2,754.7

$ 2,655.5

Property, plant and equipment and accumulated depreciation [Abstract]

Processing plants [Member] | Minimum [Member]

$ 200.9

Property, plant and equipment and accumulated depreciation [Abstract]

Processing plants [Member] | Maximum [Member]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

Pipelines and related equipment [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Pipelines and related equipment [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Terminal facilities [Member] | Minimum [Member]

45 years

Property, plant and equipment and accumulated depreciation [Abstract]

Terminal facilities [Member] | Maximum [Member]

10 years

Property, plant and equipment and accumulated depreciation [Abstract]

Office furniture and equipment [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Office furniture and equipment [Member] | Maximum [Member]

3 years

Property, plant and equipment and accumulated depreciation [Abstract]

Buildings [Member] | Minimum [Member]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

Buildings [Member] | Maximum [Member]

20 years

Property, plant and equipment and accumulated depreciation [Abstract]

Laboratory and shop equipment [Member] | Minimum [Member]

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

Laboratory and shop equipment [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground storage facilities [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Underground storage facilities [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Storage tanks [Member] | Minimum [Member]

35 years

Property, plant and equipment and accumulated depreciation [Abstract]

Storage tanks [Member] | Maximum [Member]

10 years

Property, plant and equipment and accumulated depreciation [Abstract]

Water wells [Member] | Minimum [Member]

40 years

Property, plant and equipment and accumulated depreciation [Abstract]

Water wells [Member] | Maximum [Member]

5 years

Property, plant and equipment and accumulated depreciation [Abstract]

Schedule of Equity Method Investments [Line Items]

35 years

[1]	Depreciation expense is a component of "Costs and expenses" as presented on our Statements of Consolidated Operations.
[2]	Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.
[3]	Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment and related assets
[4]	In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years.
[5]	Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets.
[6]	In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.
[7]	Platforms and facilities include offshore platforms and related facilities and other associated assets located in the Gulf of Mexico.
[8]	Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
[9]	Marine vessels include tow boats, barges and related equipment used in our marine transportation business.

Property, Plant and Equipment, Significant Sales (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Acquisitions and Disposals [Line Items]
Proceeds from disposal of assets	$ 145.3	$ 280.6	$ 1,198.8
Gains attributable to disposal of assets	102.1	83.3	86.4
Seminole Pipeline segment [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from disposal of assets	0.0	86.9	0.0
Gains attributable to disposal of assets	0.0	52.5	0.0
Lubrication oil and specialty chemical distribution assets [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from disposal of assets	$ 0.0	35.3	$ 0.0
Gains attributable to disposal of assets		$ 6.7

Investments in Unconsolidated Affiliates (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Jan. 18, 2012

Apr. 27, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Non-cash asset impairment charges

$ 3,042.0

$ 2,437.1

4.8

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

259.5

167.3

$ 64.3

Equity method investment amortization of excess cost

59.6

58.1

3.3

3.4

Forecasted amortization of excess cost amounts - 2015

3.3

Forecasted amortization of excess cost amounts - 2016

3.3

Forecasted amortization of excess cost amounts - 2017

3.3

Forecasted amortization of excess cost amounts - 2018

3.3

Forecasted amortization of excess cost amounts - 2019

3.3

NGL Pipelines & Services [Member]

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

30.6

15.7

15.9

Equity method investment amortization of excess cost

26.5

27.7

$ 1.2

1.2

1.0

NGL Pipelines & Services [Member] | Venice Energy Service Company, L.L.C. [Member]

Schedule of Equity Method Investments [Line Items]

13.10%

NGL Pipelines & Services [Member] | K/D/S Promix, L.L.C. [Member]

$ 27.7

27.6

Schedule of Equity Method Investments [Line Items]

50.00%

NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member]

$ 38.5

45.4

Schedule of Equity Method Investments [Line Items]

32.20%

NGL Pipelines & Services [Member] | Skelly-Belvieu Pipeline Company, L.L.C. [Member]

$ 18.8

19.5

Schedule of Equity Method Investments [Line Items]

50.00%

NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member]

$ 40.1

40.8

Schedule of Equity Method Investments [Line Items]

35.00%

NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member]

$ 349.3

339.9

Schedule of Equity Method Investments [Line Items]

45.00%

NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member]

$ 37.9

37.8

Schedule of Equity Method Investments [Line Items]

33.30%

Onshore Natural Gas Pipelines & Services [Member]

$ 170.0

134.5

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Onshore Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member]

$ 3.6

3.8

4.4

Schedule of Equity Method Investments [Line Items]

50.00%

Onshore Crude Oil Pipelines & Services [Member]

$ 23.2

24.2

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

184.6

140.3

32.6

Equity method investment amortization of excess cost

21.7

17.8

$ 0.9

0.7

Onshore Crude Oil Pipelines & Services [Member] | Seaway Crude Pipeline Company LLC [Member]

Schedule of Equity Method Investments [Line Items]

50.00%

Onshore Crude Oil Pipelines & Services [Member] | Eagle Ford Pipeline LLC [Member]

$ 1,431.2

940.7

Schedule of Equity Method Investments [Line Items]

50.00%

Offshore Pipelines & Services [Member]

$ 336.5

224.5

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

54.0

29.8

26.9

Equity method investment amortization of excess cost

9.0

10.0

$ 1.0

1.3

1.2

Offshore Pipelines & Services [Member] | Poseidon Oil Pipeline Company, L.L.C. [Member]

Schedule of Equity Method Investments [Line Items]

36.00%

Offshore Pipelines & Services [Member] | Cameron Highway Oil Pipeline Company [Member]

$ 31.8

41.7

Schedule of Equity Method Investments [Line Items]

50.00%

Offshore Pipelines & Services [Member] | Deepwater Gateway, L.L.C. [Member]

$ 201.3

207.7

Schedule of Equity Method Investments [Line Items]

50.00%

Offshore Pipelines & Services [Member] | Neptune Pipeline Company, L.L.C. [Member]

$ 79.6

84.5

Schedule of Equity Method Investments [Line Items]

25.70%

Non-cash asset impairment charges

$ 34.9

38.7

4.8

Offshore Pipelines & Services [Member] | Southeast Keathley Canyon Pipeline Company L.L.C. [Member]

Schedule of Equity Method Investments [Line Items]

50.00%

Petrochemical & Refined Products Services [Member]

$ 146.1

159.2

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

^[1]

(13.3)

(22.3)

(17.9)

Equity method investment amortization of excess cost

2.4

2.6

$ 0.2

0.1

0.2

Petrochemical & Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member]

Schedule of Equity Method Investments [Line Items]

30.00%

Petrochemical & Refined Products Services [Member] | Centennial Pipeline LLC [Member]

$ 6.5

7.6

Schedule of Equity Method Investments [Line Items]

50.00%

Petrochemical & Refined Products Services [Member] | Other Unconsolidated Affiliates [Member]

$ 66.1

60.1

Schedule of Equity Method Investments [Line Items]

Other Investment [Member]

2.5

2.7

Equity in income (loss) of unconsolidated affiliates by business segment [Abstract]

Unamortized excess cost amounts by business segment [Abstract]

^[2]

0.0

2.4

Equity method investment amortization of excess cost

^[3]

$ 0.0

0.3

Other Investment [Member] | Energy Transfer Equity [Member]

Other Investments [Abstract]

Percentage exceeded on ownership interests (in hundredths)

3.00%

Number of Energy Transfer Equity common units sold (in units)

22,762,636

6,540,878

Proceeds from the sale of Energy Transfer Equity common units

$ 825.1

$ 270.2

Gain on the sale of Energy Transfer Equity common units

$ 68.8

[1]	Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value.
[2]	With respect to the year ended December 31, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.
[3]	Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity through January 18, 2012, which is the date we ceased using the equity method to account for this investment.

Acquisition of Oiltanking Partners, L.P. (Details) bbl in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2014 USD ($) shares bbl	Dec. 31, 2014 USD ($) shares bbl	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Oct. 02, 2014 Dock bbl
Oiltanking Partners, L.P. [Abstract]
Cash paid to acquire business		$ 2,416.8	$ 0.0	$ 0.0
Storage capacity for crude oil and petroleum products (in Bbls) \| bbl	225	225
Oiltanking Partners L.P. [Member]
Oiltanking Partners, L.P. [Abstract]
Common units acquired (in units) \| shares	15,899,802
Subordinated units acquired (in units) \| shares	38,899,802
Total consideration for acquisition		$ 4,400.0
Number of ship and barge docks owned \| Dock					12
Storage capacity for crude oil and petroleum products (in Bbls) \| bbl					26
Revenues from acquired assets	$ 57.5
Net income from acquired assets	$ 8.1
Oiltanking Partners L.P. - Step 1 [Member]
Oiltanking Partners, L.P. [Abstract]
Common units acquired (in units) \| shares		15,899,802
Subordinated units acquired (in units) \| shares		38,899,802
Total consideration for acquisition		$ 4,609.8
Cash paid to acquire business		$ 2,210.0
Common units issued in connection with acquisition (in units) \| shares		54,807,352
Cash paid to assume notes receivable		$ 228.3
Acquisition related costs		$ 3.8

Acquisition of Oiltanking Partners, L.P., Purchase Price Allocation (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2014

Oct. 02, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Liabilities assumed in business combination:

Oiltanking Partners L.P. - Step 1 [Member]

$ 4,199.9

$ 2,080.0

$ 2,086.8

$ 2,092.3

Consideration:

Cash

2,438.3

Equity instruments (54,807,352 common units of Enterprise)

^[1]

2,171.5

Fair value of total consideration transferred in Step 1

4,609.8

Indentifiable assets acquired in business combination:

Current assets, including cash of $21.5 million

$ 68.0

Property, plant, and equipment

1,080.1

2,949.1

Liabilities assumed in business combination:

227.6

Total assets acquired

4,324.8

Current liabilities

(84.8)

(223.3)

Total liabilities assumed

^[2]

(129.7)

(437.8)

Noncontrolling interest in Oiltanking

^[3]

(1,397.2)

Total assets acquired less liabilities assumed and noncontrolling interest

2,489.8

Total consideration given for ownership interests in Oiltanking in Step 1

$ 4,609.8

Common units issued in connection with acquisition of Oiltanking (in units)

2,120.0

Oiltanking Acquisition:

Cash acquired

$ 21.5

54,807,352

Common unit price (in dollars per share)

$ 39.62

Inputs to calculate noncontrolling interests

$ 119.4

Noncontrolling interests:

28,328,890 Oiltanking common units at $49.32 per unit

Total related party notes receivable

228.3

Current portion of related party notes receivable

5.0

Long-term portion of related party notes receivable

223.3

Oiltanking Partners L.P. - Step 1 [Member] | Minimum [Member]

2.5

Noncontrolling interests:

Cash flow projections discount rate (in hundredths)

5.50%

Oiltanking Partners L.P. - Step 1 [Member] | Maximum [Member]

Noncontrolling interests:

Cash flow projections discount rate (in hundredths)

8.50%

Oiltanking Partners L.P. - Step 1 [Member] | Real Property [Member]

Indentifiable assets acquired in business combination:

Property, plant, and equipment

95.4

Oiltanking Partners L.P. - Step 1 [Member] | Personal Property [Member]

Indentifiable assets acquired in business combination:

Property, plant, and equipment

984.7

Oiltanking Partners L.P. - Step 1 [Member] | Customer relationship intangibles [Member]

Weighted-average amortization period (in years)

^[4]

1,192.4

Oiltanking Acquisition:

29 years

Oiltanking Partners L.P. - Step 1 [Member] | Contract-based intangibles [Member]

Weighted-average amortization period (in years)

^[4]

297.5

Oiltanking Acquisition:

6 years

Oiltanking Partners L.P. - Step 1 [Member] | Incentive distribution rights [Member]

$ 1,459.2

[1]	The fair value of the equity-based consideration paid in connection with Step 1 of the Oiltanking acquisition was based on the closing market price of Enterprise's common units of $39.62 per unit on the acquisition date.
[2]	Other long-term liabilities includes $119.4 million for the Liquidity Option Agreement. The fair value assigned to the Liquidity Option Agreement is provisional pending completion of certain tax-related computations. See Note 18 for information regarding this agreement.
[3]	From an accounting perspective, Enterprise acquired control of Oiltanking as a result of completing Step 1. In accordance with ASC 805, Business Combinations, the estimated fair value of Oiltanking's common units held by parties other than Enterprise following Step 1 (i.e., the "noncontrolling interest") is based on 28,328,890 common units held by third parties on October 1, 2014 multiplied by the closing unit price for Oiltanking common units on that date of $49.32 per unit.
[4]	The weighted-average amortization period for the customer relationship intangible assets is 29 years and for the contract-based intangible assets is six years.

Acquisition of Oiltanking Partners, L.P., Distributions (Details) - $ / shares	1 Months Ended		12 Months Ended
	Feb. 28, 2015	Aug. 31, 2014	Dec. 31, 2014
Oiltanking Partners L.P. [Member]
Distributions:
Distribution paid (dollars per unit)	$ 0.285	$ 0.26
Minimum quarterly distribution [Member]
Distributions:
Total quarterly distribution per unit target amount			0.16875
First target distribution [Member]
Distributions:
Total quarterly distribution per unit target amount			above $0.16875 up to $0.1940625
Second target distribution [Member]
Distributions:
Total quarterly distribution per unit target amount			above $0.1940625 up to $0.2109375
Third target distribution [Member]
Distributions:
Total quarterly distribution per unit target amount			above $0.2109375 up to $0.253125
Maximum target distribution [Member]
Distributions:
Total quarterly distribution per unit target amount			above $0.253125
General Partner [Member] \| Minimum quarterly distribution [Member]
Distributions:
Marginal percentage interest in distributions			2.00%
General Partner [Member] \| First target distribution [Member]
Distributions:
Marginal percentage interest in distributions			2.00%
General Partner [Member] \| Second target distribution [Member]
Distributions:
Marginal percentage interest in distributions			15.00%
General Partner [Member] \| Third target distribution [Member]
Distributions:
Marginal percentage interest in distributions			25.00%
General Partner [Member] \| Maximum target distribution [Member]
Distributions:
Marginal percentage interest in distributions			50.00%
Limited Partner [Member] \| Minimum quarterly distribution [Member]
Distributions:
Marginal percentage interest in distributions			98.00%
Limited Partner [Member] \| First target distribution [Member]
Distributions:
Marginal percentage interest in distributions			98.00%
Limited Partner [Member] \| Second target distribution [Member]
Distributions:
Marginal percentage interest in distributions			85.00%
Limited Partner [Member] \| Third target distribution [Member]
Distributions:
Marginal percentage interest in distributions			75.00%
Limited Partner [Member] \| Maximum target distribution [Member]
Distributions:
Marginal percentage interest in distributions			50.00%

Acquisition of Oiltanking Partners, L.P., Pro Forma Earnings Data (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Basic earnings per unit [Abstract]
As reported basic units outstanding (in units)									1,848.7	1,788.0	1,723.6
As reported basic earnings per unit (in dollars per unit)	$ 0.35	$ 0.38	$ 0.35	$ 0.44	$ 0.38	$ 0.33	$ 0.31	$ 0.43	$ 1.51	$ 1.45	$ 1.40
Diluted earnings per unit [Abstract]
As reported diluted units outstanding (in units)									1,895.2	1,842.6	1,786.4
As reported diluted earnings per unit (in dollars per unit)	$ 0.34	$ 0.37	$ 0.34	$ 0.43	$ 0.37	$ 0.32	$ 0.30	$ 0.41	$ 1.47	$ 1.41	$ 1.35
Oiltanking Partners L.P. [Member]
Pro forma earnings data [Abstract]
Revenues									$ 48,087.5	$ 47,875.7
Costs and expenses									44,509.0	44,522.3
Operating income									3,838.0	3,520.7
Net income									2,877.5	2,632.8
Net income attributable to noncontrolling interest									75.0	39.5
Net income attributable to limited partners									$ 2,802.5	$ 2,593.3
Basic earnings per unit [Abstract]
As reported basic units outstanding (in units)									1,848.7	1,788.0
Pro forma basic units outstanding (in units)									1,903.5	1,842.8
As reported basic earnings per unit (in dollars per unit)									$ 1.51	$ 1.45
Pro forma basic earnings per unit (in dollars per unit)									$ 1.47	$ 1.41
Diluted earnings per unit [Abstract]
As reported diluted units outstanding (in units)									1,895.2	1,842.6
Pro forma diluted units outstanding (in units)									1,950.0	1,897.4
As reported diluted earnings per unit (in dollars per unit)									$ 1.47	$ 1.41
Pro forma diluted earnings per unit (in dollars per unit)									$ 1.44	$ 1.37

Acquisition of Oiltanking Partners, L.P., Step 2 (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2015	Dec. 31, 2014
Oiltanking Partners, L.P. [Abstract]
Intangible assets reclassified to goodwill		$ 0
Oiltanking Partners L.P. [Member]
Oiltanking Partners, L.P. [Abstract]
Number of common units issued for each subordinated unit converted (in units)		1
Number of units owned upon conversion (in units)		54,799,604
Limited partner interests acquired (in hundredths)		65.90%
Oiltanking Partners L.P. - Step 2 [Member]
Oiltanking Partners, L.P. [Abstract]
Common units issued in connection with acquisition (in units)	36,827,557
Common units exchanged for each Oiltanking unit (in units)	1.3
Intangible assets reclassified to goodwill	$ 1,460

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Identifiable intangible assets [Abstract]
Gross Value	$ 5,548.4	$ 2,612.2
Accumulated Amortization	(1,246.3)	(1,150.0)
Carrying Value	4,302.1	1,462.2	$ 1,566.8
Amortization Expense	110.6	105.6	125.7
Forecasted amortization expense [Abstract]
2015	150.5
2016	152.3
2017	149.3
2018	142.7
2019	131.3
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	2,310.0
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	534.3
Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Carrying Value	1,460.0
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,051.1	622.1
Accumulated Amortization	(361.9)	(336.9)
Carrying Value	689.2	285.2
Amortization Expense	33.1	36.4	39.7
NGL Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	340.8	340.8
Accumulated Amortization	(183.2)	(165.7)
Carrying Value	157.6	175.1
NGL Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	277.7	281.3
Accumulated Amortization	(178.7)	(171.2)
Carrying Value	99.0	110.1
NGL Pipelines & Services [Member] \| Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	432.6	0.0
Accumulated Amortization	0.0	0.0
Carrying Value	432.6	0.0
Onshore Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,629.6	1,629.7
Accumulated Amortization	(656.7)	(611.9)
Carrying Value	972.9	1,017.8
Amortization Expense	45.0	50.1	63.4
Onshore Natural Gas Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,163.6	1,163.6
Accumulated Amortization	(308.9)	(281.2)
Carrying Value	854.7	882.4
Onshore Natural Gas Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	466.0	466.1
Accumulated Amortization	(347.8)	(330.7)
Carrying Value	118.2	135.4
Onshore Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,244.8	11.1
Accumulated Amortization	(21.2)	(6.6)
Carrying Value	2,223.6	4.5
Amortization Expense	15.7	1.4	0.9
Onshore Crude Oil Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,108.0	10.7
Accumulated Amortization	(7.7)	(6.3)
Carrying Value	1,100.3	4.4
Onshore Crude Oil Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	281.4	0.4
Accumulated Amortization	(13.5)	(0.3)
Carrying Value	267.9	0.1
Onshore Crude Oil Pipelines & Services [Member] \| Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	855.4	0.0
Accumulated Amortization	0.0	0.0
Carrying Value	855.4	0.0
Offshore Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	197.0	205.1
Accumulated Amortization	(155.4)	(150.4)
Carrying Value	41.6	54.7
Amortization Expense	9.9	11.5	11.3
Offshore Pipelines & Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	195.8	203.9
Accumulated Amortization	(154.9)	(150.0)
Carrying Value	40.9	53.9
Offshore Pipelines & Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1.2	1.2
Accumulated Amortization	(0.5)	(0.4)
Carrying Value	0.7	0.8
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	425.9	144.2
Accumulated Amortization	(51.1)	(44.2)
Carrying Value	374.8	100.0
Amortization Expense	6.9	6.2	$ 10.4
Petrochemical & Refined Products Services [Member] \| Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	198.4	104.3
Accumulated Amortization	(43.3)	(38.2)
Carrying Value	155.1	66.1
Petrochemical & Refined Products Services [Member] \| Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	56.3	39.9
Accumulated Amortization	(7.8)	(6.0)
Carrying Value	48.5	33.9
Petrochemical & Refined Products Services [Member] \| Incentive distribution rights [Member]
Identifiable intangible assets [Abstract]
Gross Value	171.2	0.0
Accumulated Amortization	0.0	0.0
Carrying Value	$ 171.2	$ 0.0

Intangible Assets and Goodwill, Goodwill (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		$ 2,080.0	$ 2,086.8	$ 2,092.3
Goodwill adjustment		0.0
Goodwill related to the sale of assets		(0.1)	(6.8)
Reclassification to assets held for sale				(5.5)
Goodwill related to Oiltanking acquisition		2,120.0
Balance at end of period		4,199.9	2,080.0	2,086.8
Fixed assets transferred			73.7
Oiltanking Partners L.P. [Member]
Changes in carrying amount of goodwill [Roll Forward]
Goodwill related to Oiltanking acquisition	$ 1,460.0	2,120.0
NGL Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		341.2	341.2	341.2
Goodwill adjustment		520.0
Goodwill related to the sale of assets		0.0	0.0
Reclassification to assets held for sale				0.0
Goodwill related to Oiltanking acquisition		1,319.2
Balance at end of period		2,180.4	341.2	341.2
Onshore Natural Gas Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		296.3	296.3	296.3
Goodwill adjustment		0.0
Goodwill related to the sale of assets		0.0	0.0
Reclassification to assets held for sale				0.0
Goodwill related to Oiltanking acquisition		0.0
Balance at end of period		296.3	296.3	296.3
Onshore Crude Oil Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		305.1	311.2	311.2
Goodwill adjustment		0.0
Goodwill related to the sale of assets		0.0	(6.1)
Reclassification to assets held for sale				0.0
Goodwill related to Oiltanking acquisition		554.8
Balance at end of period		859.9	305.1	311.2
Offshore Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		82.1	82.1	82.1
Goodwill adjustment		0.0
Goodwill related to the sale of assets		(0.1)	0.0
Reclassification to assets held for sale				0.0
Goodwill related to Oiltanking acquisition		0.0
Balance at end of period		82.0	82.1	82.1
Petrochemical & Refined Products Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		1,055.3	1,056.0	1,061.5
Goodwill adjustment		(520.0)
Goodwill related to the sale of assets		0.0	(0.7)
Reclassification to assets held for sale				(5.5)
Goodwill related to Oiltanking acquisition		246.0
Balance at end of period		$ 781.3	$ 1,055.3	$ 1,056.0

Debt Obligations (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Oct. 02, 2014

Total other, non-principal amounts

$ 21,389.2

$ 17,357.7

(25.4)

(6.2)

Less current maturities of debt

^[1]

(2,206.4)

(1,125.0)

Total long-term debt

19,157.4

16,226.5

Letters of credit outstanding for facilities and motor fuel tax obligations

2.5

Senior Debt Obligations [Member]

Senior Debt Obligations [Member] | Commercial Paper Notes [Member]

19,856.5

15,825.0

^[2]

$ 906.5

475.0

Maximum borrowing capacity

variable

$ 2,000.0

Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Minimum [Member]

Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Maximum [Member]

0.22%

Senior Debt Obligations [Member] | EPO $1.5 Billion 364-Day Credit Agreement [Member]

0.77%

$ 0.0

0.0

$ 1,500.0

variable

Maximum borrowing capacity

Sep. 29, 2015

$ 1,500.0

Maximum bank commitments increase

$ 200.0

Information regarding variable interest rates paid [Abstract]

Variable Interest Rates Paid, Minimum (in hundredths)

1.15%

Variable Interest Rates Paid, Maximum (in hundredths)

1.15%

Weighted-Average Interest Rate Paid (in hundredths)

1.15%

Senior Debt Obligations [Member] | EPO Senior Notes O [Member]

$ 0.0

500.0

fixed

9.75%

Repayment of senior notes

Jan. 31, 2014

$ 500.0

Senior Debt Obligations [Member] | EPO Senior Notes G [Member]

$ 0.0

650.0

fixed

5.60%

Repayment of senior notes

Oct. 15, 2014

$ 650.0

Senior Debt Obligations [Member] | EPO Senior Notes I [Member]

$ 250.0

250.0

fixed

5.00%

Senior Debt Obligations [Member] | EPO Senior Notes X [Member]

Mar. 01, 2015

$ 400.0

400.0

fixed

3.70%

Senior Debt Obligations [Member] | EPO Senior Notes FF [Member]

Jun. 01, 2015

$ 650.0

650.0

fixed

1.25%

Senior Debt Obligations [Member] | EPO Senior Notes AA [Member]

Aug. 13, 2015

$ 750.0

750.0

fixed

3.20%

Senior Debt Obligations [Member] | EPO Senior Notes L [Member]

Feb. 01, 2016

$ 800.0

800.0

fixed

6.30%

Senior Debt Obligations [Member] | EPO Senior Notes V [Member]

Sep. 01, 2017

$ 349.7

349.7

fixed

6.65%

Senior Debt Obligations [Member] | EPO $3.5 Billion Multi-Year Revolving Credit Facility [Member]

Apr. 15, 2018

$ 0.0

0.0

variable

Maximum borrowing capacity

Jun. 19, 2018

$ 3,500.0

Information regarding variable interest rates paid [Abstract]

Variable Interest Rates Paid, Minimum (in hundredths)

1.13%

Variable Interest Rates Paid, Maximum (in hundredths)

1.14%

Weighted-Average Interest Rate Paid (in hundredths)

1.13%

Senior Debt Obligations [Member] | EPO Senior Notes N [Member]

$ 700.0

700.0

fixed

6.50%

Senior Debt Obligations [Member] | EPO Senior Notes LL [Member]

Jan. 31, 2019

$ 800.0

0.0

fixed

2.55%

Oct. 15, 2019

Debt issued as percent of principal amount (in hundredths)

$ 800.0

99.981%

Senior Debt Obligations [Member] | EPO Senior Notes Q [Member]

$ 500.0

500.0

fixed

5.25%

Senior Debt Obligations [Member] | EPO Senior Notes Y [Member]

Jan. 31, 2020

$ 1,000.0

1,000.0

fixed

5.20%

Senior Debt Obligations [Member] | EPO Senior Notes CC [Member]

Sep. 01, 2020

$ 650.0

650.0

fixed

4.05%

Senior Debt Obligations [Member] | EPO Senior Notes HH [Member]

Feb. 15, 2022

$ 1,250.0

1,250.0

fixed

3.35%

Senior Debt Obligations [Member] | EPO Senior Notes JJ [Member]

Mar. 15, 2023

$ 850.0

0.0

fixed

3.90%

Feb. 15, 2024

Debt issued as percent of principal amount (in hundredths)

$ 850.0

99.811%

Senior Debt Obligations [Member] | EPO Senior Notes MM [Member]

$ 1,150.0

0.0

fixed

3.75%

Feb. 15, 2025

Debt issued as percent of principal amount (in hundredths)

$ 1,150.0

99.681%

Senior Debt Obligations [Member] | EPO Senior Notes D [Member]

$ 500.0

500.0

fixed

6.875%

Senior Debt Obligations [Member] | EPO Senior Notes H [Member]

Mar. 01, 2033

$ 350.0

350.0

fixed

6.65%

Senior Debt Obligations [Member] | EPO Senior Notes J [Member]

Oct. 15, 2034

$ 250.0

250.0

fixed

5.75%

Senior Debt Obligations [Member] | EPO Senior Notes W [Member]

Mar. 01, 2035

$ 399.6

399.6

fixed

7.55%

Senior Debt Obligations [Member] | EPO Senior Notes R [Member]

Apr. 15, 2038

$ 600.0

600.0

fixed

6.125%

Senior Debt Obligations [Member] | EPO Senior Notes Z [Member]

Oct. 15, 2039

$ 600.0

600.0

fixed

6.45%

Senior Debt Obligations [Member] | EPO Senior Notes BB [Member]

Sep. 01, 2040

$ 750.0

750.0

fixed

5.95%

Senior Debt Obligations [Member] | EPO Senior Notes DD [Member]

Feb. 01, 2041

$ 600.0

600.0

fixed

5.70%

Senior Debt Obligations [Member] | EPO Senior Notes EE [Member]

Feb. 15, 2042

$ 750.0

750.0

fixed

4.85%

Senior Debt Obligations [Member] | EPO Senior Notes GG [Member]

Aug. 15, 2042

$ 1,100.0

1,100.0

fixed

4.45%

Senior Debt Obligations [Member] | EPO Senior Notes II [Member]

Feb. 15, 2043

$ 1,400.0

1,000.0

fixed

4.85%

Mar. 15, 2044

Debt issued as percent of principal amount (in hundredths)

$ 400.0

100.836%

Senior Debt Obligations [Member] | EPO Senior Notes KK [Member]

$ 1,150.0

0.0

fixed

5.10%

Feb. 15, 2045

Debt issued as percent of principal amount (in hundredths)

$ 1,150.0

99.845%

Senior Debt Obligations [Member] | EPO Senior Notes NN [Member]

$ 400.0

0.0

fixed

4.95%

Oct. 15, 2054

Debt issued as percent of principal amount (in hundredths)

$ 400.0

98.356%

Senior Debt Obligations [Member] | TEPPCO Senior Notes 4 [Member]

$ 0.3

0.3

fixed

6.65%

Senior Debt Obligations [Member] | TEPPCO Senior Notes 5 [Member]

Apr. 15, 2018

$ 0.4

0.4

fixed

7.55%

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes A [Member]

Apr. 15, 2038

^[3]

$ 550.0

550.0

fixed/variable

^[4]

8.375%

Date through which interest rate is fixed

Aug. 31, 2066

^[4]

8/1/2016

Variable annual interest rate thereafter, variable rate basis

3-month LIBOR

Variable interest rate (in hundredths)

^[5]

3.7075%

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C [Member]

^[6]

$ 285.8

285.8

fixed/variable

^[7]

7.00%

Date through which interest rate is fixed

Jun. 01, 2067

9/1/2017

Variable annual interest rate thereafter, variable rate basis

3-month LIBOR

Variable interest rate (in hundredths)

^[8]

2.7775%

Junior Debt Obligations [Member] | EPO Junior Subordinated Notes B [Member]

^[9]

$ 682.7

682.7

fixed/variable

^[10]

7.034%

Date through which interest rate is fixed

Jan. 15, 2068

^[10]

1/15/2018

Variable annual interest rate thereafter, variable rate basis

3-month LIBOR

Variable interest rate (in hundredths)

^[11]

2.68%

Minimum variable annual interest rate (in hundredths)

^[11]

7.034%

Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes [Member]

$ 14.2

14.2

fixed/variable

^[7]

7.00%

Jun. 01, 2067

Senior Notes [Member]

$ 18,950.0

Segment Gross Operating Margin [Abstract]

$ 4,750.0

$ 2,250.0

$ 2,500.0

[1]	We expect to refinance the current maturities of our debt obligations at or prior to their maturity.
[2]	Principal amounts outstanding at December 31, 2014 have interest rates ranging from 0.22% and 0.77% and are due in January 2015.
[3]	Fixed rate of 8.375% through August 1, 2016; thereafter, variable rate based on 3-month LIBOR plus 3.7075%
[4]	Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007.
[5]	Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2016.
[6]	Fixed rate of 7.00% through September 1, 2017; thereafter, variable rate based on 3-month LIBOR plus 2.7775%.
[7]	Interest is payable semi-annually in arrears in June and December of each year, which commenced in December 2009.
[8]	Interest is payable quarterly in arrears in March, June, September and December of each year commencing in June 2017.
[9]	Fixed rate of 7.034% through January 15, 2018; thereafter, the rate will be the greater of 7.034% or a variable rate based on 3-month LIBOR plus 2.68%.
[10]	Interest is payable semi-annually in arrears in January and July of each year, which commenced in January 2008.
[11]	Interest is payable quarterly in arrears in January, April, July and October of each year commencing in April 2018.

Debt Obligations, Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Scheduled Maturities of Debt [Abstract]
2015	$ 2,206.5
2016	750.0
2017	800.0
2018	350.0
2019	1,500.0
After 2019	15,782.7
Total	21,389.2	$ 17,357.7
Commercial Paper Notes [Member]
Scheduled Maturities of Debt [Abstract]
2015	906.5
2016	0.0
2017	0.0
2018	0.0
2019	0.0
After 2019	0.0
Total	906.5
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
2015	1,300.0
2016	750.0
2017	800.0
2018	350.0
2019	1,500.0
After 2019	14,250.0
Total	18,950.0
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
2015	0.0
2016	0.0
2017	0.0
2018	0.0
2019	0.0
After 2019	1,532.7
Total	$ 1,532.7

Equity and Distributions, Summary of Changes in Outstanding Units (Details) - shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Common Units (Unrestricted) [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	1,864,148,802	1,789,839,702	1,755,504,404
Common units issued in connection with underwritten offerings (in units)		36,800,000	18,400,000
Common units issued in connection with at-the-market program (in units)	1,590,334	15,249,378	7,957,090
Common units issued in connection with DRIP and EUPP (in units)	9,754,227	10,308,254	5,629,320
Common units issued in connection with Step 1 of Oiltanking acquisition (in units)	54,807,352
Common units issued in connection with the vesting and exercise of unit options (in units)	1,014,108	401,764	427,828
Common units issued in connection with the vesting of phantom unit awards (in units)	23,311
Common units issued in connection with the vesting of restricted common unit awards (in units)	2,634,074	3,770,696	2,633,206
Common units issued in connection with the vesting of other types of equity-based awards (in units)			104,336
Conversion and reclassification of Class B units to common units (in units)		9,040,862
Restricted common units awards issued (in units)		0	0
Forfeiture of restricted common unit awards (in units)	0	0	0
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	(894,383)	(1,261,854)	(816,482)
Other (in units)	17,202
Ending Balance (in units)	1,933,095,027	1,864,148,802	1,789,839,702
Restricted Common Units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	7,221,214	7,786,972	7,736,432
Common units issued in connection with underwritten offerings (in units)		0	0
Common units issued in connection with at-the-market program (in units)	0	0	0
Common units issued in connection with DRIP and EUPP (in units)	0	0	0
Common units issued in connection with Step 1 of Oiltanking acquisition (in units)	0
Common units issued in connection with the vesting and exercise of unit options (in units)	0	0	0
Common units issued in connection with the vesting of phantom unit awards (in units)	0
Common units issued in connection with the vesting of restricted common unit awards (in units)	(2,634,074)	(3,770,696)	(2,633,206)
Common units issued in connection with the vesting of other types of equity-based awards (in units)			0
Conversion and reclassification of Class B units to common units (in units)		0
Restricted common units awards issued (in units)		3,549,052	3,177,476
Forfeiture of restricted common unit awards (in units)	(357,350)	(344,114)	(493,730)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	0	0	0
Other (in units)	0
Ending Balance (in units)	4,229,790	7,221,214	7,786,972
Common units [Member]
Summary of changes in outstanding units [Roll Forward]
Beginning Balance (in units)	1,871,370,016	1,797,626,674	1,763,240,836
Common units issued in connection with underwritten offerings (in units)		36,800,000	18,400,000
Common units issued in connection with at-the-market program (in units)	1,590,334	15,249,378	7,957,090
Common units issued in connection with DRIP and EUPP (in units)	9,754,227	10,308,254	5,629,320
Common units issued in connection with Step 1 of Oiltanking acquisition (in units)	54,807,352
Common units issued in connection with the vesting and exercise of unit options (in units)	1,014,108	401,764	427,828
Common units issued in connection with the vesting of phantom unit awards (in units)	23,311
Common units issued in connection with the vesting of restricted common unit awards (in units)	0	0	0
Common units issued in connection with the vesting of other types of equity-based awards (in units)			104,336
Conversion and reclassification of Class B units to common units (in units)		9,040,862
Restricted common units awards issued (in units)		3,549,052	3,177,476
Forfeiture of restricted common unit awards (in units)	(357,350)	(344,114)	(493,730)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards (in units)	(894,383)	(1,261,854)	(816,482)
Other (in units)	17,202
Ending Balance (in units)	1,937,324,817	1,871,370,016	1,797,626,674

Equity and Distributions, Issuances of Equity (Details) $ / shares in Units, $ in Millions	1 Months Ended			12 Months Ended
	Nov. 30, 2013 USD ($) $ / shares shares	Feb. 28, 2013 USD ($) $ / shares shares	Sep. 30, 2012 USD ($) $ / shares shares	Dec. 31, 2014 USD ($) shares	Dec. 31, 2013 USD ($) shares	Dec. 31, 2012 USD ($) shares	Dec. 31, 2009	Mar. 31, 2012 USD ($)
Net Cash Proceeds from Sale of Common Units [Abstract]
Net cash proceeds from the issuance of common units \| $				$ 388.8	$ 1,792.0	$ 816.8
Class B Units [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Common unit exchange ratio in connection with merger							1.24
Treasury Units [Member]
Treasury Units [Abstract]
Maximum common units authorized for repurchase under a buy-back program (in units) \| shares				4,000,000
Total of common units repurchased under a buy-back program (in units) \| shares				2,763,200
Remaining common units available for repurchase (in units) \| shares				1,236,800
Total cost of treasury units \| $				$ 30.2
Distribution Reinvestment Plan [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance (in units) \| shares				140,000,000
Remaining units available for issuance (in units) \| shares				27,481,349
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units) \| shares				9,480,407	10,024,828	5,359,696
Net cash proceeds from the issuance of common units \| $				$ 321.3	$ 287.6	$ 132.6
Distribution Reinvestment Plan [Member] \| EPCO and affiliates [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units) \| shares				2,946,241
Net cash proceeds from the issuance of common units \| $				$ 100.0
Employee Unit Purchase Plan [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance (in units) \| shares				8,000,000
Remaining units available for issuance (in units) \| shares				7,153,068
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units) \| shares				273,820	283,426	269,624
Net cash proceeds from the issuance of common units \| $				$ 9.8	$ 8.5	$ 7.1
Shelf Registration 2010 [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units) \| shares		18,400,000	18,400,000
Over-allotment of common units included in offering (in units) \| shares		2,400,000	2,400,000
Offering price of common unit (in dollars per unit) \| $ / shares		$ 27.28	$ 26.54
Net cash proceeds from the issuance of common units \| $		$ 486.6	$ 473.3
Senior notes issued under universal shelf registration \| $					$ 2,250.0	$ 2,500.0
Shelf Registration 2013 [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units) \| shares	18,400,000
Over-allotment of common units included in offering (in units) \| shares	2,400,000
Offering price of common unit (in dollars per unit) \| $ / shares	$ 31.03
Net cash proceeds from the issuance of common units \| $	$ 553.0
Senior notes issued under universal shelf registration \| $				4,750.0
2012 At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance \| $								$ 1,000.0
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units) \| shares					15,249,378	7,957,090
Gross proceeds from the sale of common units \| $					$ 460.4	$ 205.4
Net cash proceeds from the issuance of common units \| $					$ 456.3	$ 203.8
2013 At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance \| $				1,250.0
Remaining units available for issuance \| $				$ 1,190.0
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units issued (in units) \| shares				1,590,334
Gross proceeds from the sale of common units \| $				$ 58.3
Net cash proceeds from the issuance of common units \| $				$ 57.7

Equity and Distributions, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance				$ (359.0)				$ (370.4)	$ (359.0)	$ (370.4)
Other comprehensive income before reclassifications									161.7	(39.9)
Amounts reclassified from accumulated other comprehensive (income) loss									(44.3)	51.3
Total other comprehensive income (loss)									117.4	11.4	$ (19.0)
Ending Balance	$ (241.6)				$ (359.0)				(241.6)	(359.0)	(370.4)
Interest expense									921.0	802.5	771.8
Revenue	(10,190.3)	$ (12,330.2)	$ (12,520.8)	(12,909.9)	(13,101.3)	$ (12,093.3)	$ (11,149.3)	(11,383.1)	(47,951.2)	(47,727.0)	(42,583.1)
Operating costs and expenses									44,220.5	44,238.7	39,367.9
Total	(681.1)	$ (699.2)	$ (646.5)	(806.7)	(705.7)	$ (592.8)	$ (553.3)	(755.3)	(2,833.5)	(2,607.1)	(2,428.0)
Gains and Losses on Cash Flow Hedges [Member] \| Commodity derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance				(14.7)				10.1	(14.7)	10.1
Other comprehensive income before reclassifications									161.3	(46.9)
Amounts reclassified from accumulated other comprehensive (income) loss									(76.7)	22.1
Total other comprehensive income (loss)									84.6	(24.8)
Ending Balance	69.9				(14.7)				69.9	(14.7)	10.1
Gains and Losses on Cash Flow Hedges [Member] \| Interest rate derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance				(347.2)				(383.0)	(347.2)	(383.0)
Other comprehensive income before reclassifications									0.0	6.6
Amounts reclassified from accumulated other comprehensive (income) loss									32.4	29.2
Total other comprehensive income (loss)									32.4	35.8
Ending Balance	(314.8)				(347.2)				(314.8)	(347.2)	(383.0)
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Beginning Balance				$ 2.9				$ 2.5	2.9	2.5
Other comprehensive income before reclassifications									0.4	0.4
Amounts reclassified from accumulated other comprehensive (income) loss									0.0	0.0
Total other comprehensive income (loss)									0.4	0.4
Ending Balance	$ 3.3				$ 2.9				3.3	2.9	$ 2.5
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Total									(44.3)	51.3
Reclassification out of Accumulated Other Comprehensive Income [Member] \| Commodity derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Revenue									(75.0)	22.4
Operating costs and expenses									(1.7)	(0.3)
Reclassification out of Accumulated Other Comprehensive Income [Member] \| Interest rate derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Interest expense									$ 32.4	$ 29.2

Equity and Distributions, Noncontrolling Interests (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 02, 2014
Components of noncontrolling interests
Limited partners of Oiltanking other than EPO	$ 1,408.9	$ 0.0
Joint venture partners	220.1	225.6
Total	1,629.0	225.6
Components of net income attributable to noncontrolling interests
Limited partners of Oiltanking other than EPO	14.2	0.0	$ 0.0
Joint venture partners	31.9	10.2	8.1
Total	46.1	10.2	8.1
Cash distributions paid to noncontrolling interests:
Limited partners of Oiltanking other than EPO	7.7	0.0	0.0
Joint venture partners	40.9	8.9	13.3
Total	48.6	8.9	13.3
Cash contributions from noncontrolling interests:
Joint venture partners	$ 4.0	115.4	$ 6.6
Oiltanking Partners L.P. [Member]
Components of noncontrolling interests
Limited partners of Oiltanking other than EPO				$ 1,400.0
Enterprise EF78 LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Parent	75.00%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	25.00%
Initial contribution from joint venture partner		$ 90.2

Equity and Distributions, Distributions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Distributions to Partners [Abstract]
Number of Designated Units excluded from distributions	45,120,000	47,400,000	52,260,000
Number of Designated Units to be excluded from distributions during 2015	35,380,000
First Quarter 2014 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.3550
Record Date	Apr. 30, 2014
Payment Date	May 07, 2014
Second Quarter 2014 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.3600
Record Date	Jul. 31, 2014
Payment Date	Aug. 07, 2014
Third Quarter 2014 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.3650
Record Date	Oct. 31, 2014
Payment Date	Nov. 07, 2014
Fourth Quarter 2014 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)	$ 0.3700
Record Date	Jan. 30, 2015
Payment Date	Feb. 06, 2015
First Quarter 2013 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.3350
Record Date		Apr. 30, 2013
Payment Date		May 07, 2013
Second Quarter 2013 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.3400
Record Date		Jul. 31, 2013
Payment Date		Aug. 07, 2013
Third Quarter 2013 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.3450
Record Date		Oct. 31, 2013
Payment Date		Nov. 07, 2013
Fourth Quarter 2013 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.3500
Record Date		Jan. 31, 2014
Payment Date		Feb. 07, 2014

Business Segments (Details)	12 Months Ended
Business Segments (Details)	Dec. 31, 2014 Fractionator Platform Segment Truck mi
Segment Reporting Information [Line Items]
Number of reportable segments \| Segment	5
Number of miles of pipelines	51,300
Number of fractionators \| Fractionator	22
Number of offshore hub platforms \| Platform	6
NGL Pipelines and Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,300
Number of fractionators \| Fractionator	15
Onshore Natural Gas Pipelines and Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	19,300
Onshore Crude Oil Pipelines and Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	5,400
Number of tractor-trailors \| Truck	560
Offshore Pipelines And Services [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	2,350
Number of offshore hub platforms \| Platform	6
Petrochemical and Refined Products Services [Member] \| Propylene Operations [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	680
Petrochemical and Refined Products Services [Member] \| Refined Products Operations [Member]
Segment Reporting Information [Line Items]
Number of miles of pipelines	4,200

Business Segments, Gross Operating Margin (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Revenues

$ 47,951.2

$ 47,727.0

$ 42,583.1

Subtract operating costs and expenses

(44,220.5)

(44,238.7)

(39,367.9)

Add equity in income of unconsolidated affiliates

259.5

167.3

64.3

Add depreciation, amortization and accretion expense amounts not reflected in gross operating margin

1,282.7

1,148.9

1,061.7

Add impairment charges not reflected in gross operating margin

34.0

92.6

63.4

Subtract net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin

(102.1)

(83.4)

(17.6)

Add non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin

84.6

^[1]

4.4

^[1]

0.0

Subtract subsequent recognition of deferred revenues attributable to make-up rights

(2.9)

0.0

Total segment gross operating margin

5,286.5

4,818.1

4,387.0

Reconciliation of total Segment Gross Operating Margin [Abstract]

Total segment gross operating margin

5,286.5

4,818.1

4,387.0

Adjustments to reconcile total segment gross operating margin to operating income:

Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin

(1,282.7)

(1,148.9)

(1,061.7)

Subtract impairment charges not reflected in gross operating margin

(34.0)

(92.6)

(63.4)

Add net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin (see Note 20)

102.1

83.4

17.6

Subtract non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin

(84.6)

^[1]

(4.4)

^[1]

0.0

Add subsequent recognition of deferred revenues attributable to make-up rights

2.9

0.0

Subtract general and administrative costs not reflected in gross operating margin

(214.5)

(188.3)

(170.3)

Operating income

$ 921.0

$ 937.7

$ 884.3

$ 1,032.7

$ 915.5

$ 819.9

$ 774.2

$ 957.7

3,775.7

3,467.3

3,109.2

Other expense, net

(919.1)

(802.7)

(698.4)

Income before income taxes

$ 2,856.6

$ 2,664.6

$ 2,410.8

[1]	Several of our major new liquids pipeline projects experienced periods in 2013 and 2014 where shippers were unable to meet their contractual minimum volume commitments.

Business Segments, Segment Reporting Information (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

$ 47,879.7

$ 47,661.1

$ 42,509.8

71.5

65.9

73.3

0.0

Equity in income (loss) of unconsolidated affiliates

47,951.2

47,727.0

42,583.1

259.5

167.3

64.3

5,286.5

4,818.1

4,387.0

Investments in unconsolidated affiliates (see Note 9)

29,881.6

26,946.6

24,846.4

3,042.0

2,437.1

1,394.6

4,302.1

1,462.2

1,566.8

4,199.9

2,080.0

2,086.8

$ 2,092.3

NGL Pipelines and Services [Member]

41,425.6

32,925.9

29,894.6

Equity in income (loss) of unconsolidated affiliates

30.6

15.7

15.9

689.2

285.2

Onshore Natural Gas Pipelines & Services [Member]

2,180.4

341.2

Equity in income (loss) of unconsolidated affiliates

3.6

3.8

4.4

972.9

1,017.8

Onshore Crude Oil Pipelines and Services [Member]

296.3

Equity in income (loss) of unconsolidated affiliates

184.6

140.3

32.6

2,223.6

4.5

Offshore Pipelines And Services [Member]

859.9

305.1

311.2

Equity in income (loss) of unconsolidated affiliates

54.0

29.8

26.9

41.6

54.7

Petrochemical and Refined Products Services [Member]

82.0

82.1

Equity in income (loss) of unconsolidated affiliates

^[1]

(13.3)

(22.3)

(17.9)

374.8

100.0

Other Investment [Member]

781.3

1,055.3

1,056.0

$ 1,061.5

Equity in income (loss) of unconsolidated affiliates

^[2]

0.0

2.4

Reportable Business Segments [Member] | NGL Pipelines and Services [Member]

17,078.4

17,119.1

15,158.9

11.4

1.1

9.5

13,716.5

11,096.6

12,500.6

Equity in income (loss) of unconsolidated affiliates

30,806.3

28,216.8

27,669.0

30.6

15.7

15.9

2,877.7

2,514.4

2,468.5

Investments in unconsolidated affiliates (see Note 9)

11,766.9

9,957.8

8,494.8

682.3

645.5

324.6

689.2

285.2

320.6

2,180.4

341.2

Reportable Business Segments [Member] | Onshore Natural Gas Pipelines & Services [Member]

15,318.8

11,229.7

9,481.2

4,182.6

3,522.7

3,297.7

21.2

15.8

54.9

1,106.7

959.7

871.6

Equity in income (loss) of unconsolidated affiliates

5,310.5

4,498.2

4,224.2

3.6

3.8

4.4

803.3

789.0

775.5

Investments in unconsolidated affiliates (see Note 9)

8,835.5

8,917.3

8,950.1

23.2

24.2

24.9

972.9

1,017.8

1,067.9

296.3

Reportable Business Segments [Member] | Onshore Crude Oil Pipelines and Services [Member]

10,127.9

10,255.6

10,339.2

20,151.9

20,609.1

17,661.6

32.4

41.3

0.1

12,678.7

10,222.3

6,906.9

Equity in income (loss) of unconsolidated affiliates

32,863.0

30,872.7

24,568.6

184.6

140.3

32.6

762.5

742.7

387.7

Investments in unconsolidated affiliates (see Note 9)

2,332.2

1,479.9

1,385.9

1,767.7

1,165.2

493.8

2,223.6

4.5

5.9

859.9

305.1

311.2

Reportable Business Segments [Member] | Offshore Pipelines And Services [Member]

7,183.4

2,954.7

2,196.8

150.3

151.7

182.7

6.5

7.7

8.8

6.5

9.6

10.4

Equity in income (loss) of unconsolidated affiliates

163.3

169.0

201.9

54.0

29.8

26.9

162.0

146.1

173.0

Investments in unconsolidated affiliates (see Note 9)

1,145.1

1,223.7

1,343.0

493.7

531.8

479.0

41.6

54.7

66.2

82.0

82.1

Reportable Business Segments [Member] | Petrochemical and Refined Products Services [Member]

1,762.4

1,892.3

1,970.3

6,316.5

6,258.5

6,208.9

0.0

1,779.6

1,764.0

1,758.9

Equity in income (loss) of unconsolidated affiliates

8,096.1

8,022.5

7,967.8

(13.3)

(22.3)

(17.9)

681.0

625.9

579.9

Investments in unconsolidated affiliates (see Note 9)

3,047.2

2,712.4

2,559.5

75.1

70.4

72.3

374.8

100.0

106.2

781.3

1,055.3

1,056.0

Reportable Business Segments [Member] | Other Investment [Member]

4,278.4

3,938.1

3,794.0

0.0

0.0

0.0

Equity in income (loss) of unconsolidated affiliates

0.0

0.0

2.4

0.0

2.4

Investments in unconsolidated affiliates (see Note 9)

0.0

0.0

0.0

0.0

0.0

Adjustments [Member]

0.0

0.0

(29,288.0)

(24,052.2)

(22,048.4)

Equity in income (loss) of unconsolidated affiliates

(29,288.0)

(24,052.2)

(22,048.4)

0.0

0.0

Investments in unconsolidated affiliates (see Note 9)

2,754.7

2,655.5

2,113.1

0.0

0.0

0.0

Other operating costs and expenses

$ 2,754.7

$ 2,655.5

$ 2,113.1

[1]	Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value.
[2]	With respect to the year ended December 31, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.

Business Segments, Consolidated Revenues and Expenses (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Operating costs and expenses:

Cost of sales

^[1]

$ 40,464.1

$ 40,770.2

$ 36,015.5

^[2]

2,541.8

2,310.4

2,244.9

Depreciation, amortization and accretion

1,282.7

1,148.9

1,061.7

Net gains attributable to asset sales and insurance recoveries

(102.1)

(83.4)

(17.6)

Non-cash asset impairment charges

34.0

92.6

63.4

General and administrative costs

214.5

188.3

170.3

Total consolidated costs and expenses

44,435.0

44,427.0

39,538.2

Shell Oil Company [Member]

$ 10,190.3

$ 12,330.2

$ 12,520.8

$ 12,909.9

$ 13,101.3

$ 12,093.3

$ 11,149.3

$ 11,383.1

47,951.2

$ 47,727.0

$ 42,583.1

Shell Oil Company [Member] | Revenues [Member]

$ 4,052.7

Largest non-affiliated customer percentage (in hundredths)

8.50%

BP [Member] | Revenues [Member]

Largest non-affiliated customer percentage (in hundredths)

9.00%

9.50%

NGL Pipelines and Services [Member]

Sales of NGLs and related products

$ 15,460.1

$ 15,916.0

$ 14,218.5

1,629.7

1,204.2

949.9

NGL Pipelines and Services [Member] | Shell Oil Company [Member]

17,089.8

17,120.2

15,168.4

Onshore Natural Gas Pipelines & Services [Member]

615.5

Sales of natural gas

3,181.7

2,571.6

2,395.4

1,022.1

966.9

957.2

Onshore Natural Gas Pipelines & Services [Member] | Shell Oil Company [Member]

4,203.8

3,538.5

3,352.6

Onshore Crude Oil Pipelines and Services [Member]

130.3

Sales of crude oil

19,783.9

20,371.3

17,548.7

400.4

279.1

113.0

Onshore Crude Oil Pipelines and Services [Member] | Shell Oil Company [Member]

20,184.3

20,650.4

17,661.7

Offshore Pipelines And Services [Member]

3,106.0

Sales of natural gas

0.3

0.5

0.4

Sales of crude oil

8.6

5.7

3.3

147.9

153.2

187.8

Offshore Pipelines And Services [Member] | Shell Oil Company [Member]

156.8

159.4

191.5

Petrochemical and Refined Products Services [Member]

6.7

Sales of petrochemicals and refined products

5,575.5

5,568.8

5,470.9

741.0

689.7

738.0

Petrochemical and Refined Products Services [Member] | Shell Oil Company [Member]

6,316.5

$ 6,258.5

$ 6,208.9

Total provision for (benefit from) income taxes

$ 194.2

[1]	Cost of sales is a component of "Operating costs and expenses," as presented on our Statements of Consolidated Operations. Year-to-year fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
[2]	Represents cost of operating our plants, pipelines and other fixed assets, excluding depreciation, amortization and accretion charges.

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 15, 2015
Revenues - related parties:
Total revenue - related parties	$ 71.5	$ 65.9	$ 73.3
Costs and expenses - related parties:
Total costs and expenses - related parties	1,122.9	1,052.2	857.1
Accounts receivable - related parties:
Total accounts receivable - related parties	2.8	6.8
Accounts payable - related parties:
Total accounts payable - related parties	118.9	150.5
Related Party Transactions [Abstract]
Operating costs and expenses	992.1	937.9	765.7
General and administrative expenses	130.8	114.3	91.4
EPCO and affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	939.9	892.2	816.9
Accounts payable - related parties:
Total accounts payable - related parties	98.1	116.3
Distributions:
Total cash distributions	877.0	811.4	750.2
Related Party Transactions [Abstract]
Operating costs and expenses	801.7	770.7	719.4
General and administrative expenses	$ 138.2	121.5	97.5
Relationship with Affiliates [Abstract]
Number of Units (in units)	684,721,631
Percentage of Total Units Outstanding (in hundredths)	35.30%
Enterprise common units pledged as security (in units)				180,000,000
Unconsolidated affiliates [Member]
Revenues - related parties:
Total revenue - related parties	$ 71.5	65.9	73.3
Costs and expenses - related parties:
Total costs and expenses - related parties	183.0	160.0	40.2
Accounts receivable - related parties:
Total accounts receivable - related parties	2.8	6.8
Accounts payable - related parties:
Total accounts payable - related parties	20.8	34.2
Unconsolidated affiliates [Member] \| Seaway Crude Pipeline Company [Member]
Revenues - related parties:
Total revenue - related parties	29.4	41.3
Costs and expenses - related parties:
Total costs and expenses - related parties	130.8	132.4	18.1
Unconsolidated affiliates [Member] \| K/D/S Promix, L.L.C. [Member]
Revenues - related parties:
Total revenue - related parties	11.1	9.8	7.8
Costs and expenses - related parties:
Total costs and expenses - related parties	25.8	28.1	27.4
Unconsolidated affiliates [Member] \| Texas Express Pipeline LLC [Member]
Revenues - related parties:
Total revenue - related parties	9.1
Unconsolidated affiliates [Member] \| Eagle Ford Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	25.8	5.4
Unconsolidated affiliates [Member] \| Other investments in unconsolidated subsidiaries [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ 24.5	$ 21.8	19.4
Unconsolidated affiliates [Member] \| Evangeline [Member]
Revenues - related parties:
Total revenue - related parties			$ 42.9

Provision for Income Taxes (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Current:

Federal

$ 2.2

$ (0.5)

$ 18.9

State

13.4

19.3

28.9

Foreign

1.4

0.8

1.2

Total current

17.0

19.6

49.0

Deferred:

Federal

2.2

(0.5)

(64.7)

State

3.5

38.9

(1.4)

Foreign

0.4

(0.5)

(0.1)

Total deferred

6.1

37.9

(66.2)

23.1

57.5

(17.2)

Reconciliation of the provision for income taxes [Abstract]

Pre-Tax Net Book Income ("NBI")

2,856.6

2,664.6

2,410.8

Texas Margin Tax

^[1]

17.5

58.3

23.5

State income taxes (net of federal benefit)

0.2

(0.1)

5.3

Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities

1.5

(1.4)

(1.6)

Valuation allowance

0.0

(2.0)

Expiration of tax net operating loss

0.0

0.1

2.4

Tax gain on conversion of corporate subsidiaries into limited liability companies

0.0

(45.3)

Other permanent differences

3.9

0.6

0.5

Total provision for (benefit from) income taxes

$ 23.1

$ 57.5

$ (17.2)

Effective income tax rate (in hundredths)

0.80%

2.20%

(0.70%)

Deferred tax assets:

Net operating loss carryovers

^[2]

$ 0.3

$ 0.1

Employee benefit plans

0.3

0.2

Accruals

1.5

2.0

Total deferred tax assets

2.1

2.3

Less: Deferred tax liabilities:

Property, plant and equipment

64.4

59.8

Equity investment in partnerships

4.1

2.9

Total deferred tax liabilities

68.5

62.7

Total net deferred tax liabilities

66.4

60.4

Current portion of total net deferred tax assets

0.2

0.4

Long-term portion of total net deferred tax liabilities

$ 66.6

60.8

Income tax expense due to changes in Texas Margin Tax

$ 19.6

[1]	Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
[2]	These losses expire in various years between 2015 and 2028 and are subject to limitations on their utilization.

Earnings Per Unit (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Numerator:

Net income attributable to limited partners

$ 659.8

$ 691.1

$ 637.7

$ 798.8

$ 698.9

$ 592.0

$ 552.5

$ 753.5

$ 2,787.4

$ 2,596.9

$ 2,419.9

Undistributed earnings allocated and cash payments on phantom unit awards

^[1]

(5.2)

0.0

Net income available to common unitholders

$ 2,782.2

$ 2,596.9

$ 2,419.9

Denominator:

Basic weighted-average number of common units outstanding (in units)

1,848.7

1,788.0

1,723.6

Basic earnings per unit:

Basic earnings per unit (in dollars per unit)

$ 0.35

$ 0.38

$ 0.35

$ 0.44

$ 0.38

$ 0.33

$ 0.31

$ 0.43

$ 1.51

$ 1.45

$ 1.40

Numerator:

Net income attributable to limited partners

$ 659.8

$ 691.1

$ 637.7

$ 798.8

$ 698.9

$ 592.0

$ 552.5

$ 753.5

$ 2,787.4

$ 2,596.9

$ 2,419.9

Denominator:

Distribution-bearing common units (in units)

1,848.7

1,788.0

1,723.6

Designated Units (in units)

42.7

46.8

51.0

Class B units (in units)

^[2]

0.0

5.4

9.0

Phantom units (in units)

^[1]

2.9

0.0

Incremental option units (in units)

0.9

2.4

2.8

Total (in units)

1,895.2

1,842.6

1,786.4

Diluted earnings per unit:

Diluted earnings per unit (in dollars per unit)

$ 0.34

$ 0.37

$ 0.34

$ 0.43

$ 0.37

$ 0.32

$ 0.30

$ 0.41

$ 1.47

$ 1.41

$ 1.35

[1]

Each phantom unit award includes a DER, which entitles the recipient to receive cash payments equal to the product of the number of phantom unit awards and the cash distribution per unit paid to Enterprise's common unitholders. Cash payments made in connection with DERs are nonforfeitable. As a result, the phantom units are considered participating securities for purposes of computing basic earnings per unit. Phantom unit awards were first issued in February 2014.

[2]

The Class B units automatically converted into an equal number of distribution-bearing common units in August 2013.

Commitments and Contingencies (Details) bbl in Millions, $ in Millions, BTU in Trillions	12 Months Ended
	Dec. 31, 2014 USD ($) BTU bbl	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Redelivery commitments [Abstract]
Redelivery commitments of natural gas (in Btus) \| BTU	9.2
Redelivery commitments of crude oil (in MMBbls) \| bbl	9.3
Redelivery commitments of NGL and petrochemical products (in MMBbls) \| bbl	28.3
Operating lease obligations [Abstract]
Minimum term of material lease agreements (in years)	5 years
Maximum term of material lease agreements (in years)	30 years
Renewal option years for certain leases (in years)	20 years
Lease and rental expense included in costs and expenses	$ 94.2	$ 87.6	$ 95.1
Liabilities, Other than Long-term Debt, Noncurrent [Abstract]
Noncurrent portion of asset retirement obligations	83.2	82.5
Deferred revenues - non-current portion	73.0	54.6
Liquidity Option Agreement	119.4	0.0
Centennial guarantees	7.0	7.8
Other	28.2	27.4
Total	310.8	172.3
Junior Subordinated Note [Member]
Debt Instrument [Line Items]
Debt obligations	1,530.0
Centennial Pipeline LLC [Member]
Debt Instrument [Line Items]
Debt obligations	75.8
Litigation matters [Member]
Loss Contingencies [Line Items]
Litigation accruals on an undiscounted basis	2.4	$ 3.7
Litigation matters [Member] \| ETP Lawsuit [Member]
Loss Contingencies [Line Items]
Loss contingency, damages awarded	319.4
Loss contingency, total damages sought	535.8
Loss contingency, disgorgement damages sought	150.0
Prejudgment interest	$ 66.4
Post-judgment interest rate (in hundredths)	5.00%
Centennial debt guarantee [Member]
Guarantor Obligations [Line Items]
Percentage of debt obligations guaranteed (in hundredths)	50.00%
Guarantee of debt obligations	$ 37.9
Fair value of debt guarantee	5.4
Centennial cash call guarantee [Member]
Guarantor Obligations [Line Items]
Cash call guarantee	50.0
Fair value of cash call guarantee	$ 2.4

Commitments and Contingencies, Contractual Obligations (Details) bbl in Millions, $ in Millions, BTU in Trillions	Dec. 31, 2014 USD ($) bbl BTU	Dec. 31, 2013 USD ($)
Scheduled maturities of debt obligations [Abstract]
2015	$ 2,206.5
2016	750.0
2017	800.0
2018	350.0
2019	1,500.0
Thereafter	15,782.7
Total	21,389.2	$ 17,357.7
Estimated cash interest payments [Abstract]
2015	1,005.6
2016	968.6
2017	953.0
2018	899.6
2019	846.8
Thereafter	16,630.3
Total	21,303.9
Operating lease obligations [Abstract]
2015	60.5
2016	62.0
2017	56.4
2018	48.9
2019	42.3
Thereafter	272.6
Total	542.7
Natural Gas [Member]
Estimated payment obligations:
2015	637.5
2016	539.1
2017	295.5
2018	295.5
2019	195.1
Thereafter	177.0
Total	$ 2,139.7
Underlying major volume commitments:
2015 \| BTU	255
2016 \| BTU	219
2017 \| BTU	128
2018 \| BTU	128
2019 \| BTU	82
Thereafter \| BTU	67
Total \| BTU	879
NGLs [Member]
Estimated payment obligations:
2015	$ 391.1
2016	26.4
2017	26.3
2018	28.9
2019	14.3
Thereafter	0.0
Total	$ 487.0
Underlying major volume commitments:
2015 \| bbl	17
2016 \| bbl	3
2017 \| bbl	4
2018 \| bbl	4
2019 \| bbl	2
Thereafter \| bbl	0
Total \| bbl	30
Crude Oil [Member]
Estimated payment obligations:
2015	$ 2,279.1
2016	37.4
2017	37.3
2018	37.3
2019	34.1
Thereafter	0.0
Total	$ 2,425.2
Underlying major volume commitments:
2015 \| bbl	38
2016 \| bbl	1
2017 \| bbl	1
2018 \| bbl	1
2019 \| bbl	0
Thereafter \| bbl	0
Total \| bbl	41
Petrochemicals And Refined Products [Member]
Estimated payment obligations:
2015	$ 956.7
2016	493.1
2017	49.5
2018	0.0
2019	0.0
Thereafter	0.0
Total	$ 1,499.3
Underlying major volume commitments:
2015 \| bbl	15
2016 \| bbl	7
2017 \| bbl	1
2018 \| bbl	0
2019 \| bbl	0
Thereafter \| bbl	0
Total \| bbl	23
Estimated Payment Obligations Other [Member]
Estimated payment obligations:
2015	$ 38.1
2016	9.2
2017	6.9
2018	4.2
2019	4.2
Thereafter	9.2
Total	71.8
Service Payment Commitments [Member]
Estimated payment obligations:
2015	200.6
2016	181.4
2017	154.9
2018	86.7
2019	66.1
Thereafter	161.1
Total	850.8
Capital Expenditure Commitments [Member]
Estimated payment obligations:
2015	1,299.8
2016	0.0
2017	0.0
2018	0.0
2019	0.0
Thereafter	0.0
Total	$ 1,299.8

Commitments and Contingencies, Liquidity Option Agreement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Oct. 02, 2014
Liquidity Option Agreement [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Probability weighted discounted cash flows	$ 119.4
Liquidity Option Agreement [Member] \| 50% Probability [Member] \| M&B exercises option; OTA owns 100% of units
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Number of units held by limited partner (in units)	54,800,000
Discounted cash flows	$ 164.7
Probability weighted discounted cash flows	$ 82.4
Liquidity Option Agreement [Member] \| 20% Probability [Member] \| M&B exercises option; OTA owns 75% of units
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Number of units held by limited partner (in units)	41,100,000
Discounted cash flows	$ 123.5
Probability weighted discounted cash flows	$ 24.7
Liquidity Option Agreement [Member] \| 10% Probability [Member] \| M&B exercises option; OTA owns 50% of units
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Number of units held by limited partner (in units)	27,400,000
Discounted cash flows	$ 82.4
Probability weighted discounted cash flows	$ 8.2
Liquidity Option Agreement [Member] \| 10% Probability [Member] \| M&B exercises option; OTA owns 25% of units
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Number of units held by limited partner (in units)	13,700,000
Discounted cash flows	$ 41.2
Probability weighted discounted cash flows	$ 4.1
Liquidity Option Agreement [Member] \| 10% Probability [Member] \| M&B does not exercise option
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Number of units held by limited partner (in units)	0
Discounted cash flows	$ 0.0
Probability weighted discounted cash flows	$ 0.0
Level 3 [Member] \| Liquidity Option Agreement [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, Expected life of OTA following option exercise (in years)	30
Fair value inputs, Interest rate on assumed debt of OTA following option exercise	4.9% over 30 years
Fair value inputs, federal and state tax rate (in hundredths)	38.00%
Cash flow projections discount rate (in hundredths)	7.40%
Liquidity Option Agreement [Abstract]
Liquidity Option Agreement	$ 119.4
Level 3 [Member] \| Liquidity Option Agreement [Member] \| Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization (in hundredths)	14.00%
Fair value inputs, OTA ownership interest in Enterprise common units (in hundredths)	2.80%
Fair value inputs, Forecasted yield on Enterprise common units (in hundredths)	5.50%
Level 3 [Member] \| Liquidity Option Agreement [Member] \| Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization (in hundredths)	3.00%
Fair value inputs, OTA ownership interest in Enterprise common units (in hundredths)	1.90%
Fair value inputs, Forecasted yield on Enterprise common units (in hundredths)	4.00%
Oiltanking Partners L.P. - Step 1 [Member]
Business Acquisition [Line Items]
Common units issued in connection with acquisition (in units)	54,807,352
Liquidity Option Agreement [Abstract]
Liquidity Option Agreement		$ 119.4
Oiltanking Partners L.P. - Step 1 [Member] \| Maximum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Cash flow projections discount rate (in hundredths)	8.50%
Oiltanking Partners L.P. - Step 1 [Member] \| Minimum [Member]
Fair Value Measurements, Recurring, Valuation Techniques [Line Items]
Cash flow projections discount rate (in hundredths)	5.50%

Significant Risks and Uncertainties (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Insurance Matters [Abstract]
Minimum insurance deductible per incident	$ 5.0
Maximum insurance deductible per incident	$ 60.0
Shell Oil Company [Member] \| Revenues [Member]
Revenue, Major Customer [Line Items]
Largest non-affiliated customer percentage (in hundredths)	8.50%
February 2011 West Storage Incident [Member]
Loss Contingencies [Line Items]
Gains related to property damage proceeds	$ 95.0	$ 15.0	$ 30.0
Proceeds from property damage insurance recoveries	$ 95.0	$ 15.0	$ 30.0

Supplemental Cash Flow Information (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Decrease (increase) in:

Accounts receivable - trade

$ 1,685.4

$ (1,136.2)

$ 161.5

3.8

(3.6)

35.3

(105.6)

38.6

(227.8)

(74.6)

(6.3)

(12.6)

18.7

2.4

(39.6)

Increase (decrease) in:

(141.0)

(10.1)

34.1

(31.6)

23.6

(84.3)

(1,647.8)

1,043.8

(422.5)

31.3

3.5

12.7

Net effect of changes in operating accounts

141.3

(35.1)

(14.4)

Other liabilities

11.9

(18.2)

(24.9)

(108.2)

(97.6)

(582.5)

Cash payments for interest, net of $77.9 , $133.0 and $116.8 capitalized in 2014, 2013 and 2012, respectively

832.1

781.5

757.3

Interest capitalized

^[1]

77.9

133.0

116.8

Cash payments for federal and state income taxes

16.1

35.0

44.8

Liability for construction in progress expenditures

372.8

205.3

221.7

Significant Acquisitions and Disposals [Line Items]

Net gains (losses) attributable to disposal of assets

145.3

280.6

1,198.8

102.1

83.3

86.4

Energy Transfer Equity [Member]

Significant Acquisitions and Disposals [Line Items]

Net gains (losses) attributable to disposal of assets

0.0

1,095.3

0.0

68.8

Seminole Pipeline segment [Member]

Significant Acquisitions and Disposals [Line Items]

Net gains (losses) attributable to disposal of assets

0.0

86.9

0.0

0.0

52.5

0.0

Pipeline Line Fill [Member]

Significant Acquisitions and Disposals [Line Items]

Lubrication oil and specialty chemical distribution assets [Member]

27.5

65.0

0.0

Significant Acquisitions and Disposals [Line Items]

Net gains (losses) attributable to disposal of assets

0.0

35.3

0.0

6.7

Chemical Trucking Assets [Member]

Significant Acquisitions and Disposals [Line Items]

West Storage Facilities [Member]

0.0

29.5

0.0

Significant Acquisitions and Disposals [Line Items]

Net gains (losses) attributable to disposal of assets

95.0

15.0

30.0

95.0

15.0

30.0

Other Disposal of Assets [Member]

Significant Acquisitions and Disposals [Line Items]

Net gains (losses) attributable to disposal of assets

22.8

48.9

73.5

$ 7.1

$ 15.8

$ (12.4)

[1]	Capitalized interest is a component of "Interest expense" as presented on our Statements of Consolidated Operations.

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information (Unaudited) [Abstract]
Revenues	$ 10,190.3	$ 12,330.2	$ 12,520.8	$ 12,909.9	$ 13,101.3	$ 12,093.3	$ 11,149.3	$ 11,383.1	$ 47,951.2	$ 47,727.0	$ 42,583.1
Operating income	921.0	937.7	884.3	1,032.7	915.5	819.9	774.2	957.7	3,775.7	3,467.3	3,109.2
Net income	681.1	699.2	646.5	806.7	705.7	592.8	553.3	755.3	2,833.5	2,607.1	2,428.0
Net income attributable to limited partners	$ 659.8	$ 691.1	$ 637.7	$ 798.8	$ 698.9	$ 592.0	$ 552.5	$ 753.5	$ 2,787.4	$ 2,596.9	$ 2,419.9
Earnings per unit:
Basic earnings per unit (in dollars per unit)	$ 0.35	$ 0.38	$ 0.35	$ 0.44	$ 0.38	$ 0.33	$ 0.31	$ 0.43	$ 1.51	$ 1.45	$ 1.40
Diluted earnings per unit (in dollars per unit)	$ 0.34	$ 0.37	$ 0.34	$ 0.43	$ 0.37	$ 0.32	$ 0.30	$ 0.41	$ 1.47	$ 1.41	$ 1.35

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Condensed Consolidating Financial Information, Balance Sheets (Details) - USD ($)
$ in Millions

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

$ 74.4

$ 122.5

3,823.0

5,475.5

2.8

6.8

1,014.2

1,093.1

576.3

325.5

5,490.7

7,023.4

29,881.6

26,946.6

$ 24,846.4

3,042.0

2,437.1

4,302.1

1,462.2

1,566.8

4,199.9

2,080.0

2,086.8

$ 2,092.3

184.4

189.4

47,100.7

40,138.7

^[1]

2,206.4

1,125.0

773.8

723.7

118.9

150.5

3,853.3

5,608.7

335.5

304.3

585.8

326.5

7,873.7

8,238.7

19,157.4

16,226.5

66.6

60.8

310.8

172.3

Equity:

18,063.2

15,214.8

1,629.0

225.6

19,692.2

15,440.4

$ 13,296.0

$ 12,219.3

Eliminations and Adjustments [Member]

47,100.7

40,138.7

0.0

0.0

(4.0)

(0.2)

0.0

0.8

0.0

(3.2)

(0.2)

0.0

(18,187.2)

(15,214.5)

0.0

0.0

0.0

(18,190.4)

(15,214.7)

0.0

0.0

(4.0)

(0.2)

0.0

0.0

0.0

(1.5)

(4.0)

(1.7)

0.0

4.1

2.9

0.0

Equity:

(18,163.4)

(15,189.9)

(27.1)

(26.0)

(18,190.5)

(15,215.9)

Subsidiary Issuer (EPO) [Member]

(18,190.4)

(15,214.7)

18.7

93.9

1,128.5

1,986.8

158.8

384.7

831.8

948.5

537.7

140.9

2,675.5

3,554.8

2,871.7

1,945.0

36,937.5

30,819.9

2,527.3

76.9

1,956.1

458.9

139.3

123.5

47,107.4

36,979.0

2,206.4

1,125.0

216.6

103.0

1,226.5

1,541.8

1,570.0

2,388.6

335.4

304.2

130.8

92.3

5,685.7

5,554.9

19,142.5

16,211.6

4.9

4.3

10.9

11.8

Equity:

22,263.4

15,196.4

0.0

22,263.4

15,196.4

Other Subsidiaries (Non-guarantor) [Member]

47,107.4

36,979.0

70.4

49.5

2,698.2

3,491.1

1,114.6

1,348.1

182.8

145.4

346.3

191.4

4,412.3

5,225.5

26,912.0

24,999.7

3,556.4

2,921.2

1,292.4

1,385.3

1,621.1

45.8

67.2

37,840.0

36,220.0

0.0

571.4

641.6

173.3

333.8

2,287.9

3,224.5

0.7

0.1

763.7

242.4

3,797.0

4,442.4

14.9

58.5

55.0

180.8

160.5

Equity:

33,720.6

31,475.9

68.2

71.3

33,788.8

31,547.2

Consolidated EPO and Subsidiaries [Member]

37,840.0

36,220.0

74.4

122.5

3,823.0

5,475.5

6.8

1,014.2

1,093.1

575.5

325.5

5,493.9

7,023.4

29,881.6

26,946.6

3,042.0

2,437.1

4,302.1

1,462.2

4,199.9

2,080.0

184.4

189.3

47,103.9

40,138.6

2,206.4

1,125.0

773.2

723.7

118.9

150.7

3,853.3

5,608.7

335.5

304.3

585.8

328.0

7,873.1

8,240.4

19,157.4

16,226.5

62.5

57.9

191.4

172.3

Equity:

18,163.4

15,189.9

1,656.1

251.6

19,819.5

15,441.5

Consolidated EPO and Subsidiaries [Member] | Eliminations and Adjustments [Member]

47,103.9

40,138.6

(14.7)

(20.9)

(3.7)

(2.4)

(1,266.6)

(1,726.0)

(0.4)

(0.8)

(308.5)

(6.8)

(1,593.9)

(1,756.9)

97.9

1.9

(37,451.9)

(31,304.0)

482.4

0.0

622.7

0.0

(0.7)

(1.4)

(37,843.5)

(33,060.4)

0.0

(14.8)

(20.9)

(1,280.9)

(1,724.9)

(4.6)

(4.4)

(0.6)

0.0

(308.7)

(6.7)

(1,609.6)

(1,756.9)

0.0

(0.9)

(1.4)

(0.3)

0.0

Equity:

(37,820.6)

(31,482.4)

1,587.9

180.3

(36,232.7)

(31,302.1)

Enterprise Products Partners L.P. (Guarantor) [Member]

(37,843.5)

(33,060.4)

0.0

0.0

0.0

0.2

0.0

0.0

0.0

0.2

0.0

18,187.2

15,214.5

0.0

0.0

0.0

0.1

18,187.2

15,214.8

0.0

0.6

0.0

4.0

0.0

0.0

0.0

0.0

4.6

0.0

0.0

0.0

119.4

0.0

Equity:

18,063.2

15,214.8

0.0

18,063.2

15,214.8