ENTERPRISE PRODUCTS PARTNERS L P (Form: 10-Q, Received: 05/08/2015 09:02:47)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations .

For the Three Months Ended March 31, 2015 and 2014.

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2014, as filed on March 2, 2015 (the “2014 Form 10-K”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Unless the context requires otherwise, references to “we,” “us,” “our,” “Enterprise” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to “EPO” mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business. Enterprise is managed by its general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Enterprise GP; (ii) Dr. Ralph S. Cunningham; and (iii) Richard H. Bachmann. Each of the DD LLC Trustees also currently serves as one of the three managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. A majority of the outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Williams, who serves as Chairman of EPCO; (ii) Dr. Cunningham, who serves as a Vice Chairman of EPCO; and (iii) Mr. Bachmann, who serves as the President and Chief Executive Officer (“CEO”) of EPCO. Each of the EPCO Trustees is also a director of EPCO.

In addition to owning our general partner, EPCO and its privately held affiliates owned approximately 34.6% of our limited partner interests at March 31, 2015.

References to “Oiltanking” and “Oiltanking GP” mean Oiltanking Partners, L.P. and OTLP GP, LLC, the general partner of Oiltanking, respectively. In October 2014, we acquired approximately 65.9% of the limited partner interests of Oiltanking, all of the member interests of Oiltanking GP and the incentive distribution rights (“IDRs”) held by Oiltanking GP from Oiltanking Holding Americas, Inc. (“OTA”) as the first step of a two-step acquisition of Oiltanking. In February 2015, we completed the second step of this acquisition. See “Significant Recent Developments” within this Part I, Item 2 for information regarding the completion of this acquisition.

As generally used in the energy industry and in this quarterly report, the acronyms below have the following meanings:

/d	= per day	MMBbls	= million barrels
BBtus	= billion British thermal units	MMBPD	= million barrels per day
Bcf	= billion cubic feet	MMBtus	= million British thermal units
BPD	= barrels per day	MMcf	= million cubic feet
MBPD	= thousand barrels per day	TBtus	= trillion British thermal units

Cautionary Statement Regarding Forward-Looking Information

This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such

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expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under “Risk Factors” within Part I, Item 1A included in our 2014 Form 10-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the filing date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Overview of Business

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 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 51,000 miles of onshore and offshore pipelines; 225 MMBbls of storage capacity for NGLs, petrochemicals, refined products and crude oil; and 14 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.

On February 13, 2015, we completed our acquisition of Oiltanking. See “Significant Recent Developments” within this Part I, Item 2 for information regarding this acquisition.

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. 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 (“ASA”) or by other service providers.

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. For information regarding our business segments, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

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Significant Recent Developments

The following information highlights selected commercial and operational developments since January 1, 2015. For information regarding recent offerings of our equity and debt securities, see “Liquidity and Capital Resources” within this Part I, Item 2.

Plans to Construct New Crude Oil and Condensate Pipeline from Midland to Houston, Texas

In April 2015, we announced the execution of long-term agreements that support development of a new 24-inch diameter pipeline (the “Midland-to-Houston” pipeline) that would transport increasing volumes of crude oil and condensate from the Permian Basin to markets in Southeast Texas. The new pipeline will originate at our Midland, Texas crude oil terminal and extend 416 miles to our Sealy storage facility, which is located west of Houston, Texas. Volumes arriving at Sealy would then be transported to our Enterprise Crude Houston (“ECHO”) terminal in southeast Houston using our Rancho II pipeline, which is currently under construction and expected to be complete in July 2015. Through ECHO, shippers will have direct access to every refinery in Houston, Texas City, Beaumont and Port Arthur, as well as our dock facilities. The Midland-to-Houston pipeline is expected to have a transportation capacity of up to 540 MBPD and commence operations in the second quarter of 2017.

Plans to Construct Natural Gas Processing Facility in Delaware Basin

In April 2015, we formed a 50/50 joint venture with an affiliate of Occidental Petroleum Corporation to develop a new 150 MMcf/d cryogenic natural gas processing facility that will accommodate growing production of NGL-rich natural gas from the Delaware Basin. The facility will be supported by long-term, firm contracts and is expected to begin operations in mid-2016. We will serve as construction manager for the project and operator once the new facility commences operations. The location of the new facility is under evaluation and is expected to be finalized in the second quarter of 2015.

Increase in NGL Loading Capacity at our Houston Ship Channel LPG Export Terminal

In September 2013, we announced an expansion project at our Houston Ship Channel LPG export terminal that would increase our ability to load cargoes from 7.5 MMBbls per month to approximately 9.0 MMBbls per month. This project was completed in April 2015.

In January 2014, we announced a further expansion of this export terminal that is expected to increase our loading capability from approximately 9.0 MMBbls per month to in excess of 16.0 MMBbls per month by the end of 2015. We expect our maximum loading capacity at this terminal to be approximately 27,000 barrels per hour once this expansion project is completed. Our expansion projects at this terminal are supported by long-term LPG sales agreements with exporters.

Formation of Panola Pipeline Joint Venture

In February 2015, we formed a joint venture involving our Panola NGL Pipeline with affiliates of Anadarko Petroleum Corporation (“Anadarko”), DCP Midstream Partners, LP (“DCP”) and MarkWest Energy Partners, L.P. (“MarkWest”). We will continue to serve as operator of the Panola Pipeline and own 55% of the member interests in the joint venture. Affiliates of Anadarko, DCP and MarkWest will own the remaining 45% member interests, with each holding a 15% interest.

The Panola Pipeline transports mixed NGLs from points near Carthage, Texas to Mont Belvieu, Texas and supports the Haynesville and Cotton Valley oil and gas production areas. In January 2015, we announced an expansion project involving the Panola Pipeline consisting of the installation of 60 miles of new pipeline, as well as pumps and other related equipment designed to increase the system’s throughput capacity by 50 MBPD to approximately 100 MBPD. The incremental capacity is expected to be available in the first quarter of 2016.

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Completion of Oiltanking Acquisition

In October 2014, we completed the first step of a two-step acquisition of Oiltanking by paying approximately $4.41 billion to OTA for Oiltanking GP, the related IDRs and approximately 65.9% of the limited partner interests of Oiltanking. As a second step of the Oiltanking acquisition (separately negotiated by the conflicts committee of Oiltanking GP on behalf of Oiltanking), we entered into an Agreement and Plan of Merger (the “merger agreement”) with Oiltanking in November 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; and

all outstanding common units of Oiltanking at the effective time of the merger held by Oiltanking’s public unitholders (which consisted 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 our ownership interests) voting to approve the merger on February 13, 2015. Upon approval of the merger, a total of 36,827,517 of our common units were issued to Oiltanking’s former public unitholders. With the completion of this second step, total consideration paid by Enterprise for Oiltanking was approximately $5.9 billion.

On February 23, 2015, we received a Civil Investigative Demand and a related Subpoena Duces Tecum from the Federal Trade Commission (“FTC”) requesting specified information relating to the Oiltanking acquisition and Enterprise’s operations. On April 13, 2015, we received a Civil Investigative Demand issued by the Attorney General of the State of Texas requesting copies of the same information and any correspondence with the FTC. We are in the process of complying with the requests and are cooperating with the investigations. Based on the limited information that we have at this time, we are unable to predict the outcome of the investigations.

For information regarding changes in our goodwill and equity balances as a result of completing the Oiltanking acquisition, see Notes 8 and 10, respectively, of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

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Results of Operations

Summarized Consolidated Income Statement Data

The following table summarizes the key components of our results of operations for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015			2014
Revenues	$	7,472.5		$	12,909.9
Costs and expenses:
Operating costs and expenses:
Cost of sales		5,678.1			11,052.7
Other operating costs and expenses		559.8			607.2
Depreciation, amortization and accretion expenses		345.3			301.4
Net gains attributable to asset sales and insurance recoveries		(0.1	)		(89.6	)
Non-cash asset impairment charges		33.3			8.8
Total operating costs and expenses		6,616.4			11,880.5
General and administrative costs		49.3			53.2
Total costs and expenses		6,665.7			11,933.7
Equity in income of unconsolidated affiliates		89.2			56.5
Operating income		896.0			1,032.7
Interest expense		(239.1	)		(220.9	)
Other, net		0.5			(0.3	)
Provision for income taxes		(6.8	)		(4.8	)
Net income		650.6			806.7
Net income attributable to noncontrolling interests		(14.5	)		(7.9	)
Net income attributable to limited partners	$	636.1		$	798.8

The following table presents each business segment’s contribution to revenues (net of eliminations) for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015		2014
NGL Pipelines & Services:
Sales of NGLs and related products	$	2,242.2	$	4,795.8
Midstream services		434.1		383.7
Total		2,676.3		5,179.5
Onshore Natural Gas Pipelines & Services:
Sales of natural gas		476.3		953.2
Midstream services		257.6		251.4
Total		733.9		1,204.6
Onshore Crude Oil Pipelines & Services:
Sales of crude oil		2,570.7		4,873.4
Midstream services		107.3		84.9
Total		2,678.0		4,958.3
Offshore Pipelines & Services:
Sales of natural gas		--		0.2
Sales of crude oil		1.1		2.1
Midstream services		34.1		34.6
Total		35.2		36.9
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products		1,151.0		1,356.2
Midstream services		198.1		174.4
Total		1,349.1		1,530.6
Total consolidated revenues	$	7,472.5	$	12,909.9

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Selected Energy Commodity Price Data

The following table presents index prices for natural gas, crude oil and selected NGL and petrochemical products for the periods indicated:

													Polymer		Refinery
	Natural						Normal				Natural		Grade		Grade		WTI		LLS
	Gas,		Ethane,		Propane,		Butane,		Isobutane,		Gasoline,		Propylene,		Propylene,		Crude Oil,		Crude Oil,
	$/MMBtu		$/gallon		$/gallon		$/gallon		$/gallon		$/gallon		$/pound		$/pound		$/barrel		$/barrel
	(1)		(2)		(2)		(2)		(2)		(2)		(3)		(3)		(4)		(4)
2014 by quarter:
1st Quarter	$	4.95	$	0.34	$	1.30	$	1.39	$	1.42	$	2.12	$	0.73	$	0.61	$	98.68	$	104.43
2nd Quarter	$	4.68	$	0.29	$	1.06	$	1.25	$	1.30	$	2.21	$	0.70	$	0.57	$	102.99	$	105.55
3rd Quarter	$	4.07	$	0.24	$	1.04	$	1.25	$	1.28	$	2.11	$	0.71	$	0.58	$	97.21	$	100.94
4th Quarter	$	4.04	$	0.21	$	0.76	$	0.98	$	0.99	$	1.49	$	0.69	$	0.52	$	73.15	$	76.08
2014 Averages	$	4.43	$	0.27	$	1.04	$	1.22	$	1.25	$	1.98	$	0.71	$	0.57	$	93.01	$	96.75

2015 by quarter:
1st Quarter	$	2.99	$	0.19	$	0.53	$	0.68	$	0.68	$	1.10	$	0.50	$	0.37	$	48.63	$	52.83

(1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc. (2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service. (3) Polymer grade propylene prices represent average contract pricing for such product as reported by Chemical Market Associates, Inc. (“CMAI”). Refinery grade propylene prices represent weighted-average spot prices for such product as reported by CMAI. (4) Crude oil prices are based on commercial index prices for WTI as measured on the New York Mercantile Exchange (“NYMEX”) and for LLS as reported by Platts.

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. Energy commodity prices fluctuate for a variety of reasons, including supply and demand imbalances and geopolitical tensions.

§	The market price of WTI crude oil (as measured on the NYMEX) averaged $48.63 per barrel in the first quarter of 2015 compared to $98.68 per barrel in the first quarter of 2014. Crude oil prices have been depressed since the fourth quarter of 2014 due to the current worldwide oversupply situation.

The market price of natural gas (as measured at the Henry Hub in Louisiana) averaged $2.99 per MMBtu in the first quarter of 2015 compared to $4.95 per MMBtu in the first quarter of 2014. Natural gas prices in the first quarter of 2014 were higher than normal due to unusually cold weather during that period. Prices in the first quarter of 2015 decreased primarily due to higher natural gas inventory levels in storage.

The weighted-average indicative market price for NGLs (based on prices for such products at Mont Belvieu, Texas , which is the primary industry hub for domestic NGL production ) was $0.54 per gallon in the first quarter of 2015 compared to $1.13 per gallon in the first quarter of 2014. In general, NGL prices have declined since the fourth quarter of 2014 due to oversupply of certain products and lower crude oil prices.

A decrease in our consolidated marketing revenues due to lower energy commodity sales prices may not result in a decrease in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be lower due to comparable decreases in the purchase prices of the underlying energy commodities. The same correlation would be true in the case of higher energy commodity sales prices and purchase costs.

We attempt to mitigate any commodity price exposure through our hedging activities as well as through converting keepwhole and similar contracts to fee-based arrangements. See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our commodity hedging activities.

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Consolidated Income Statement Highlights

The following information highlights significant changes in our comparative income statement amounts and the primary drivers of such changes.

Revenues . Total revenues for the first quarter of 2015 decreased $5.44 billion when compared to total revenues for the first quarter of 2014. Revenues from the marketing of NGLs, crude oil, natural gas and petrochemicals decreased $5.61 billion quarter-to-quarter primarily due to lower sales prices. Revenues from the marketing of refined products increased a net $64.4 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $254.7 million increase, partially offset by lower sales prices, which accounted for a $190.3 million decrease. Revenues from midstream services increased $102.2 million quarter-to-quarter primarily due to the ongoing expansion of our operations. Recently completed assets such the ATEX pipeline and a portion of the Aegis Ethane Pipeline, expanded crude oil storage capacity at our ECHO terminal and certain assets at our Mont Belvieu complex contributed approximately $40 million of this quarter-to-quarter increase. Revenues for the first quarter of 2015 include $47.8 million from services provided by the terminal assets we now own due to our acquisition of Oiltanking effective October 1, 2014.

Operating costs and expenses . Total operating costs and expenses for the first quarter of 2015 decreased $5.26 billion when compared to the first quarter of 2014. The cost of sales associated with our marketing of NGLs, crude oil, petrochemicals and natural gas decreased $5.41 billion quarter-to-quarter primarily due to lower purchase prices. The cost of sales associated with our marketing of refined products increased a net $54.4 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $254.2 million increase, partially offset by lower purchase prices, which accounted for a $199.8 million decrease.

Other operating costs and expenses decreased $47.4 million quarter-to-quarter primarily due to lower fuel and maintenance costs, which accounted for a $30.1 million decrease. Other operating costs and expenses for the first quarter of 2015 includes $13.9 million of expenses attributable to the marine terminal assets we now own as a result of acquiring Oiltanking. This amount is partially offset by $8.6 million of terminaling fees that we paid Oiltanking during the first quarter of 2014.

Depreciation, amortization and accretion expenses in operating costs and expenses for the first quarter of 2015 increased $43.9 million when compared to the first quarter of 2014 primarily due to the ongoing expansion of our operations. This quarter-to-quarter increase includes $24.0 million of depreciation and amortization expenses in the first quarter of 2015 attributable to our acquisition of Oiltanking.

In the first quarter of 2014, we recognized $95.0 million of gains attributable to the receipt of nonrefundable cash insurance proceeds. These proceeds were attributable to property damage claims we filed in connection with the February 2011 NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility.

Operating costs and expenses also include $33.3 million and $8.8 million of non-cash asset impairment charges for the first quarters of 2015 and 2014, respectively. Our non-cash asset impairment charges for the first quarter of 2015 primarily relate to crude oil and natural gas pipeline assets in Texas.

General and administrative costs . General and administrative costs for the first quarter of 2015 decreased $3.9 million when compared to the first quarter of 2014 primarily due to costs we incurred during the first quarter of 2014 for the settlement of litigation associated with our merger in 2010 with Enterprise GP Holdings L.P.

Equity in income of unconsolidated affiliates . Equity income from our unconsolidated affiliates for the first quarter of 2015 increased $32.7 million when compared to the first quarter of 2014. This increase is primarily due to increased earnings from our investments in crude oil and NGL pipeline joint ventures.

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Interest expense . Interest expense increased $18.2 million for the first quarter of 2015 when compared to the first quarter of 2014. The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015			2014
Interest charged on debt principal outstanding	$	257.1		$	232.9
Impact of interest rate hedging program, including related amortization		4.7			1.4
Interest costs capitalized in connection with construction projects (1)		(29.6	)		(18.5	)
Other (2)		6.9			5.1
Total	$	239.1		$	220.9

(1) Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) ratably over the estimated useful life of the asset once the asset enters its intended service. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital spending levels and the interest rates charged on borrowings.
(2) Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs.

Interest charged on debt principal outstanding, which is the primary driver of interest expense, increased a net $24.2 million quarter-to-quarter primarily due to increased debt principal amounts outstanding during the first quarter of 2015, which accounted for a $46.5 million increase, partially offset by the effect of lower overall interest rates in the first quarter of 2015, which accounted for a $22.3 million decrease. Our weighted-average debt principal balance for the first quarter of 2015 was $21.67 billion compared to $17.76 billion for the first quarter of 2014. In general, our debt principal balances have increased over time due to the partial debt financing of our capital spending program. For a discussion of our consolidated debt obligations and capital spending program, see “Liquidity and Capital Resources” within this Part I, Item 2.

Provision for income taxes . Provision for income taxes increased $2.0 million for the first quarter of 2015 when compared to the first quarter of 2014. The increase in expense is attributable to our state tax obligations under the Revised Texas Franchise Tax.

Noncontrolling interests . Net income attributable to noncontrolling interests increased $6.6 million for the first quarter of 2015 when compared to the first quarter of 2014. This increase is primarily due to the inclusion of noncontrolling interests in Oiltanking from January 1, 2015 to February 13, 2015, which is the date we completed the Oiltanking acquisition.

Business Segment Highlights

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. The following table presents gross operating margin by segment for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015		2014
NGL Pipelines & Services	$	695.2	$	780.0
Onshore Natural Gas Pipelines & Services		204.5		220.4
Onshore Crude Oil Pipelines & Services		214.0		159.7
Offshore Pipelines & Services		46.1		39.3
Petrochemical & Refined Products Services		174.6		130.4
Total	$	1,334.4	$	1,329.8

For additional information regarding our use of this non-GAAP financial measure, see “Other Items – Use of Non-GAAP Financial Measures” within this Part I, Item 2.

The following information highlights significant changes in our quarter-to-quarter segment results (i.e., gross operating margin amounts) and the primary drivers of such changes. The selected volume statistics presented

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in the tabular information for each segment are reported on a net basis, taking into account our ownership interests in certain joint ventures, and reflect the periods in which we owned an interest in such operations. These statistics reflect volumes for newly constructed assets from the dates such assets were placed into service.

NGL Pipelines & Services . The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2015		2014
Segment gross operating margin:
Natural gas processing and related NGL marketing activities	$	240.2	$	349.2
NGL pipelines and related storage		328.2		290.2
NGL fractionation		126.8		140.6
Total	$	695.2	$	780.0
Selected volumetric data:
NGL transportation volumes (MBPD)		2,690		2,838
NGL fractionation volumes (MBPD)		798		792
Equity NGL production (MBPD) (1)		134		137
Fee-based natural gas processing (MMcf/d) (2)		4,784		4,715

(1) Represents the NGL volumes we earn and take title to in connection with our processing activities.
(2) Volumes reported correspond to the revenue streams earned by our gas plants.

Natural gas processing and related NGL marketing activities

Gross operating margin from natural gas processing and related NGL marketing activities for the first quarter of 2015 decreased $109.0 million when compared to the first quarter of 2014. Gross operating margin from our NGL marketing activities for the first quarter of 2015 decreased a net $59.2 million when compared to the first quarter of 2014 primarily due to lower sales margins, which accounted for a $75.4 million decrease, partially offset by a $17.8 million increase due to higher sales volumes. In the first quarter of 2015, more volume in the LPG export business was associated with long-term, fee-based marketing contracts compared to higher margin spot business in the first quarter of 2014. Gross operating margin from our South Texas, Meeker, Pioneer and Chaco natural gas processing plants decreased $45.3 million in the aggregate primarily due to lower processing margins.

NGL pipelines and related storage

Gross operating margin from NGL pipelines and related storage assets for the first quarter of 2015 increased $38.0 million when compared to the first quarter of 2014. Gross operating margin from our Houston Ship Channel marine terminal and related pipeline increased $20.6 million quarter-to-quarter, of which $14.6 million of the increase is attributable to our acquisition of Oiltanking and $6.0 million to a combined 55 MBPD increase in volumes.

Collectively, gross operating margin from our investments in the Front Range Pipeline, Texas Express Pipeline and Texas Express Gathering System increased $7.9 million quarter-to-quarter primarily due to a combined 48 MBPD increase in transportation volumes (net to our interest). Gross operating margin from our ATEX pipeline increased a net $5.5 million quarter-to-quarter primarily due to higher transportation volumes of 22 MBPD. Gross operating margin from our South Texas NGL Pipeline System increased $5.0 million quarter-to-quarter primarily due to higher transportation and other fees.

Transportation volumes on the Mid-America Pipeline System and Seminole Pipeline decreased a combined 202 MBPD quarter-to-quarter due in part to increased ethane rejection during the first quarter of 2015 when compared to the first quarter of 2014. Ethane rejection at natural gas processing plants in the regions served by our Mid-America Pipeline System and Seminole Pipeline results in lower volumes of ethane available for transportation. Gross operating margin from the Mid-America Pipeline System, Seminole Pipeline and related terminals increased slightly quarter-to-quarter. Higher transportation tariffs and other fees, which accounted for a $12.2 million quarter-to-quarter increase in gross operating margin and an $18.0 million quarter-to-quarter decrease in operating expenses

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were substantially offset by a $29.9 million decrease in gross operating margin due to lower transportation volumes. Gross operating margin from our Dixie Pipeline decreased $5.3 million quarter-to-quarter primarily due to a 37 MBPD decrease in transportation volumes.

NGL fractionation

Gross operating margin from NGL fractionation for the first quarter of 2015 decreased $13.8 million when compared to the first quarter of 2014. Gross operating margin from our Mont Belvieu NGL fractionators decreased a net $6.6 million quarter-to-quarter primarily due to lower energy commodity prices, which resulted in a combined $14.3 million decrease in fractionation fees and product blending revenues, partially offset by a $7.8 million increase due to higher NGL fractionation volumes of 26 MBPD (net to our interest). Gross operating margin from our Hobbs NGL fractionator in Gaines County, Texas decreased a net $4.6 million quarter-to-quarter primarily due to lower fractionation volumes of 21 MBPD. Gross operating margin from our Norco NGL fractionator in Louisiana decreased $2.9 million quarter-to-quarter primarily due to lower revenues from product blending and percent-of-liquids contracts attributable to lower energy commodity prices.

Onshore Natural Gas Pipelines & Services . The following table presents segment gross operating margin and selected volumetric data for the Onshore Natural Gas Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2015		2014
Segment gross operating margin	$	204.5	$	220.4
Selected volumetric data:
Natural gas transportation volumes (BBtus/d)		12,503		12,520

Gross operating margin from our onshore natural gas pipelines and services segment for the first quarter of 2015 decreased $15.9 million when compared to the first quarter of 2014. Gross operating margin from our Texas Intrastate System decreased $11.9 million quarter-to-quarter primarily due to an increase in maintenance and other operating expenses. Gross operating margin from our San Juan Gathering System decreased $8.1 million quarter-to-quarter primarily due to lower gathering fees, which are indexed to natural gas prices. Gross operating margin from our Jonah Gathering System increased $4.8 million quarter-to-quarter primarily due to higher volumes of 103 BBtus/d, which accounted for a $2.5 million increase, and higher gathering fees, which accounted for an additional $1.9 million increase.

Onshore Crude Oil Pipelines & Services . The following table presents segment gross operating margin and selected volumetric data for the Onshore Crude Oil Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2015		2014
Segment gross operating margin	$	214.0	$	159.7
Selected volumetric data:
Crude oil transportation volumes (MBPD)		1,384		1,260

Gross operating margin from our onshore crude oil pipelines and services segment for the first quarter of 2015 increased $54.3 million when compared to the first quarter of 2014. Gross operating margin from crude oil terminaling services at our Houston Ship Channel terminal, which we now own due to our acquisition of Oiltanking, contributed $25.3 million in the first quarter of 2015.

Gross operating margin from our equity investment in the Seaway Pipeline increased $22.6 million quarter-to-quarter primarily due to contributions from the Seaway Loop, which commenced operations in December 2014. The quarter-to-quarter increase in gross operating margin from this investment includes an $8.4 million increase in transportation revenues associated with shipper make-up rights that are deferred under GAAP and not reflected in our consolidated equity in income of unconsolidated affiliates. Seaway’s transportation volumes increased a net 37

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MBPD quarter-to-quarter (net to our interest) with a 64 MBPD increase in long-haul volumes partially offset by a 27 MBPD decrease in combined short-haul volumes on the Texas City and Freeport Systems.

Gross operating margin from our Red River System increased $7.4 million quarter-to-quarter primarily due to lower operating expenses.

Offshore Pipelines & Services . The following table presents segment gross operating margin and selected volumetric data for the Offshore Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2015		2014
Segment gross operating margin	$	46.1	$	39.3
Selected volumetric data:
Natural gas transportation volumes (BBtus/d)		619		569
Crude oil transportation volumes (MBPD)		340		335
Platform natural gas processing (MMcf/d)		124		147
Platform crude oil processing (MBPD)		15		17

Gross operating margin from our offshore pipelines and services segment for the first quarter of 2015 increased $6.8 million when compared to the first quarter of 2014. Gross operating margin for the first quarter of 2015 includes $9.4 million of equity earnings from our investment in the SEKCO Oil Pipeline, which started earning firm capacity reservation fees in the third quarter of 2014. Aggregate gross operating margin from our Independence Hub platform and Independence Trail pipeline decreased $2.8 million quarter-to-quarter primarily due to lower platform processing and pipeline transportation volumes during the first quarter of 2015.

Petrochemical & Refined Products Services . The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted):

	For the Three Months Ended March 31,
	2015		2014
Segment gross operating margin:
Propylene fractionation and related activities	$	64.4	$	49.0
Butane isomerization and related operations		6.9		22.3
Octane enhancement and related plant operations		1.1		0.2
Refined products pipelines and related activities		86.3		42.5
Marine transportation and other		15.9		16.4
Total	$	174.6	$	130.4

Selected volumetric data:
Propylene fractionation volumes (MBPD)		74		73
Butane isomerization volumes (MBPD)		62		80
Standalone DIB processing volumes (MBPD)		65		74
Octane additive and related plant production volumes (MBPD)		8		6
Transportation volumes, primarily refined products and petrochemicals (MBPD)		803		703

Propylene fractionation and related activities

Gross operating margin from our propylene fractionation and related activities increased $15.4 million quarter-to-quarter primarily due to higher propylene sales margins, which accounted for an $11.3 million increase, and higher sales volumes, which accounted for an additional $6.2 million increase.

Butane isomerization and deisobutanizer operations

Gross operating margin from our butane isomerization and deisobutanizer (“DIB”) operations decreased $15.4 million quarter-to-quarter primarily due to lower by-product sales revenues. By-product sales revenues

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decreased $10.0 million quarter-to-quarter, of which $6.7 million is due to lower sales prices and the remaining $3.3 million is due to lower sales volumes.

Octane enhancement and HPIB plant operations

Gross operating margin from our octane enhancement facility and high purity isobutylene (“HPIB”) plant increased slightly quarter-to-quarter. Higher sales volumes, which accounted for a $7.1 million quarter-to-quarter increase in gross operating margin, and a $0.9 million decrease in operating expenses were substantially offset by a $7.3 million quarter-to-quarter decrease in gross operating margin due to lower sales margins. Production volumes for the octane enhancement facility for both quarterly periods were impacted by the facility’s planned annual major maintenance activities.

Refined products pipelines and related activities

Gross operating margin from refined products pipelines and related marketing activities increased $43.8 million quarter-to-quarter. Gross operating margin from our TE Products Pipeline and related refined products terminals increased $25.7 million quarter-to-quarter primarily due to higher tariffs and other fees, which accounted for a $10.4 million increase, and a $14.6 million quarter-to-quarter decrease in operating expenses (e.g., lower fuel and maintenance costs). Overall, transportation volumes on the TE Products Pipeline increased a net 55 MBPD quarter-to-quarter primarily due to higher refined products and petrochemical transportation volumes. Our Beaumont Refined Products Export Terminal, which we reactivated in May 2014, contributed $5.9 million of gross operating margin for the first quarter of 2015 on throughput volumes of 65 MBPD.

Gross operating margin for the first quarter of 2015 includes $7.8 million and $5.5 million from refined products terminaling services provided at our Beaumont Marine West Terminal and Houston Ship Channel terminal, respectively. We own these terminals due to our acquisition of Oiltanking effective October 1, 2014.

Liquidity and Capital Resources

At March 31, 2015, we had $3.69 billion of consolidated liquidity, which was comprised of $81.1 million of unrestricted cash on hand and $3.61 billion of available borrowing capacity under EPO’s revolving credit facilities. Based on current market conditions (as of the filing date of this quarterly report), we believe we will have sufficient liquidity, cash flow from operations and access to capital markets to fund our capital expenditures and working capital needs for the reasonably foreseeable future.

We expect to issue additional equity and debt securities to assist us in meeting our future funding and liquidity requirements, including those related to capital spending. We have a universal shelf registration statement (the “2013 Shelf”) on file with the SEC. The 2013 Shelf allows Enterprise Products Partners L.P. and EPO (on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. We issued $2.5 billion of senior notes under the 2013 Shelf in May 2015 (see below).

Consolidated Debt

The following table presents scheduled maturities of our consolidated debt obligations outstanding at March 31, 2015 for the years indicated (dollars in millions):

			Scheduled Maturities of Debt
	Total		Remainder of 2015		2016		2017		2018		2019		Thereafter
Commercial Paper	$	1,388.0	$	1,388.0	$	--	$	--	$	--	$	--	$	--
Senior Notes		18,700.0		1,050.0		750.0		800.0		350.0		1,500.0		14,250.0
Junior Subordinated Notes		1,532.7		--		--		--		--		--		1,532.7
Total	$	21,620.7	$	2,438.0	$	750.0	$	800.0	$	350.0	$	1,500.0	$	15,782.7

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

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Issuance of $2.5 Billion of Senior Notes in May 2015 . On May 7, 2015, EPO issued $750 million in principal amount of 1.65% senior notes due May 2018 (“Senior Notes OO”), $875 million in principal amount of 3.70% senior notes due February 2026 (“Senior Notes PP”) and $875 million in principal amount of 4.90% senior notes due May 2046 (“Senior Notes QQ”). Senior Notes OO, PP and QQ were issued at 99.881%, 99.635% and 99.635% of their principal amounts, respectively.

Net proceeds from the issuance of these senior notes were used as follows: (i) the repayment of amounts outstanding under EPO’s commercial paper program, which included amounts we used to repay $250 million in principal amount of Senior Notes I that matured in March 2015, (ii) the repayment of amounts outstanding at the maturity of our $400 million in principal amount of Senior Notes X due June 2015 and (iii) for general company purposes.

Enterprise Products Partners L.P. has unconditionally guaranteed these senior notes on an unsecured and unsubordinated basis. These senior notes rank equal with EPO’s existing and future unsecured and unsubordinated indebtedness and are senior to any existing and future subordinated indebtedness of EPO. These senior notes are subject to make-whole redemption rights and were issued under an indenture containing certain covenants, which generally restrict EPO’s ability (with certain exceptions) to incur debt secured by liens and engage in sale and leaseback transactions.

Issuance of Common Units

The following information describes significant transactions that affected our partners’ equity accounts during the three months ended March 31, 2015:

Completion of Oiltanking Acquisition . On February 13, 2015, we issued 36,827,517 common units to the former public unitholders of Oiltanking as a result of completing Step 2 of the Oiltanking acquisition. See “Significant Recent Developments” within this Part I, Item 2 for additional information regarding the Oiltanking acquisition.

At-The-Market Program . We have a registration statement on file 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.

During the three months ended March 31, 2015, we issued 12,350,761 common units under this program for aggregate gross proceeds of $407.8 million. This includes 3,225,057 common units sold in March 2015 to a privately held affiliate of EPCO, which generated gross proceeds of $100 million. After taking into account applicable costs, our transactions under the at-the-market program resulted in aggregate net cash proceeds of $404.2 million for the first quarter of 2015.

In April 2015, we sold an additional 2,913,000 common units under the at-the-market program for aggregate gross proceeds of $96.8 million (net proceeds of $96.1 million). As of April 30, 2015, we have the capacity to issue additional common units under this program up to an aggregate sales price of $687.1 million.

DRIP and EUPP . 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”). We issued a total of 1,869,079 common units under our DRIP during the three months ended March 31, 2015, which generated net cash proceeds of $61.7 million. After taking into account the number of common units issued under the DRIP through March 31, 2015, we have the capacity to issue an additional 25,612,270 common units under this plan. In May 2015, affiliates of privately held EPCO purchased a total of $50 million of common units through the DRIP.

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 our employee unit purchase plan (“EUPP”). We issued 71,753

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common units under our EUPP during the three months ended March 31, 2015, which generated net cash proceeds of $2.5 million. After taking into account the number of common units issued under the EUPP through March 31, 2015, we may issue an additional 7,081,315 common units under this plan.

Use of Proceeds . The net cash proceeds we received from the issuance of common units during the three months ended March 31, 2015 were used to temporarily reduce amounts outstanding under EPO’s commercial paper program and revolving credit facility and for general company purposes.

For additional information regarding our issuance of common units and related registration statements, see Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

Credit Ratings

As of May 5, 2015, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s and Baa1 from Moody’s. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s and P-2 from Moody’s. Fitch Ratings issued non-solicited ratings of BBB+ and F-2 for EPO’s long-term senior unsecured debt securities and short-term senior unsecured debt securities, respectively.

EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.

	For the Three Months Ended March 31,
	2015			2014
Net cash flows provided by operating activities	$	954.0		$	1,404.1
Cash used in investing activities		889.1			861.5
Ca sh provided by (used in) finan cing activities		(58.2	)		388.9

Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. As a result, these cash flows are exposed to certain risks. We operate predominantly in the midstream energy industry. We provide products and services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. The products that we process, sell, transport or store are principally used as fuel for residential, agricultural and commercial heating; as feedstocks in petrochemical manufacturing; by crude oil refineries; and in the production of motor gasoline. Reduced demand for our services or products by industrial customers, whether because of a decline in general economic conditions, reduced demand for the end products made with our products, or increased competition from other service providers or producers due to pricing differences or other reasons, could have a negative impact on our earnings and operating cash flows. For a more complete discussion of these and other risk factors pertinent to our business, see “Risk Factors” under Part I, Item 1A of our 2014 Form 10-K.

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Comparison of Three Months Ended March 31, 2015 with Three Months Ended March 31, 2014

The following information highlights significant quarter-to-quarter fluctuations in our consolidated cash flow amounts:

Operating Activities . Net cash flows provided by operating activities for the first quarter of 2015 decreased $450.1 million when compared to the first quarter of 2014. The decrease in cash provided by operating activities was primarily due to:

§	a $481.5 million quarter-to-quarter decrease in cash primarily due to the timing of cash receipts and payments related to operations; and

a $31.3 million decrease in cash attributable to lower partnership income in the first quarter of 2015 compared to the first quarter of 2014 (after adjusting our $156.1 million quarter-to-quarter decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); partially offset by

§	a $62.7 million increase quarter-to-quarter in cash distributions from unconsolidated affiliates primarily due to improved results from our investments in crude oil and NGL pipeline joint ventures.

For information regarding significant quarter-to-quarter changes in our consolidated net income and underlying segment results, see “Results of Operations” within this Part I, Item 2.

Investing Activities . Cash used in investing activities for the first quarter of 2015 increased $27.6 million when compared to the first quarter of 2014 primarily due to:

§	a $97.8 million quarter-to-quarter increase in capital spending for consolidated property, plant and equipment, net of contributions in aid of construction costs;

§	a $95.0 million quarter-to-quarter decrease in cash proceeds from insurance recoveries (see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report for additional information regarding proceeds from insurance recoveries); and

§	a $50.5 million quarter-to-quarter change in restricted cash requirements; partially offset by

§	a $216.4 million quarter-to-quarter decrease in cash contributions to our unconsolidated affiliates primarily due to the completion of construction of the Front Range Pipeline and the Seaway Loop, partially offset by increased investments in the Eagle Ford Crude Oil Pipeline System.

Financing Activities . Our net cash outflow for financing activities for the first quarter of 2015 was $58.2 million compared to a net cash inflow from financing activities for the first quarter of 2014 of $388.9 million. The $447.1 million quarter-to-quarter change in cash flow from financing activities was primarily due to:

a $792.2 million quarter-to-quarter decrease in net borrowings under our consolidated debt agreements. EPO repaid $250.0 million in principal amount of senior notes during the first quarter of 2015, compared to the issuance of $2.0 billion and repayment of $500.0 million in principal amount of senior notes during the first quarter of 2014. In addition, net cash inflows attributable to the issuance of short-term notes under EPO’s commercial paper program were $479.3 million during the first quarter of 2015 compared to net repayments of $475.1 million during the first quarter of 2014; and

a $64.6 million quarter-to-quarter increase in cash distributions paid to limited partners during the first quarter of 2015 when compared to the first quarter of 2014. The increase in cash distributions is due to increases in both the number of distribution-bearing common units outstanding and the quarterly cash distribution rates per unit; partially offset by

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a $385.4 million quarter-to-quarter increase in net cash proceeds from the issuance of common units. We issued an aggregate 14,291,593 common units in connection with our at-the-market program, DRIP and EUPP during the first quarter of 2015, which generated $468.4 million of net cash proceeds. This compares to an aggregate 2,676,930 common units we issued in connection with our DRIP and EUPP during the first quarter of 2014, which collectively generated $83.0 million of net cash proceeds.

Cash Distributions to Limited Partners

Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business including, for example, those for capital expenditures, debt service, working capital, operating expenses, commitments and contingencies and other significant amounts. The retention of cash by the partnership allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets. Based on the level of available cash, management proposes a quarterly cash distribution rate to the Board of Directors of Enterprise GP, which has sole authority in approving such matters. Unlike most master limited partnerships, our general partner has a non-economic ownership interest in us and is not entitled to receive any cash distributions from us based on IDRs or other equity interests.

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We measure available cash by reference to distributable cash flow. The following table summarizes our calculation of distributable cash flow for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015			2014
Net income attributable to limited partners (1)	$	636.1		$	798.8
Adjustments to GAAP net income attributable to limited partners to derive non-GAAP distributable cash flow:
Add depreciation, amortization and accretion expenses		367.4			319.9
Add asset impairment charges		33.3			8.8
Subtract net gains attributable to asset sales and insurance recoveries		(0.1	)		(89.6	)
Add cash proceeds from asset sales and insurance recoveries (2)		0.5			96.3
Add cash distributions received from unconsolidated affiliates (3)		134.4			71.7
Subtract equity in income of unconsolidated affiliates (3)		(89.2	)		(56.5	)
Subtract sustaining capital expenditures (4)		(50.7	)		(78.3	)
Add deferred income tax expense or subtract benefit, as applicable		1.5			0.2
Other, net		(3.5	)		15.7
Distributable cash flow	$	1,029.7		$	1,087.0

Total cash distributions paid to limited partners with respect to period	$	735.7		$	650.5

Cash distribution per unit declared by Enterprise GP with respect to period (5)	$	0.3750		$	0.3550

Total distributable cash flow retained by partnership with respect to period (6)	$	294.0		$	436.5

Distribution coverage ratio (7)		1.4x			1.7x

(1) For a discussion of significant changes in our comparative income statement amounts underlying net income attributable to limited partners, along with the primary drivers of such changes, see “Consolidated Income Statements Highlights” within this Part I, Item 2. (2) For a discussion of significant changes in cash proceeds from asset sales and insurance recoveries as presented in the investing activities section of our Unaudited Condensed Statements of Consolidated Cash Flows, see “Cash Flows from Operating, Investing and Financing Activities” within this Part I, Item 2. (3) For information regarding our unconsolidated affiliates, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. (4) For a discussion of our capital spending activity, see “Capital Spending” within this Part I, Item 2. Sustaining capital expenditures for each period include accruals. (5) See Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our quarterly cash distributions declared with respect to the periods presented. (6) At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these years was primarily reinvested in our growth capital spending program, which substantially reduced our reliance on the equity and debt capital markets to fund such major expenditures. (7) Distribution coverage ratio determined by dividing distributable cash flow by total cash distributions paid to limited partners and in connection with distribution equivalent rights with respect to the period.

For additional information regarding non-GAAP distributable cash flow, see “Other Items – Use of Non-GAAP Financial Measures” within this Part I, Item 2. Our use of distributable cash flow for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, the most comparable GAAP measure.

Capital Spending

An important part of our business strategy involves expansion through growth capital projects, business combinations and investments in joint ventures. We believe that we are positioned to continue to expand our system of assets through the construction of new facilities and to capitalize on expected increases in natural gas, NGL and crude oil production resulting from development activities in the Rocky Mountains, Mid-Continent, Northeast and U.S. Gulf Coast regions, including the Niobrara, Barnett, Eagle Ford, Permian, Haynesville, Marcellus and Utica Shale plays and deepwater Gulf of Mexico production fields.

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Although our focus in recent years has been on expansion through growth capital projects, management continues to analyze potential business combinations, asset acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. In light of current business conditions, we expect that these opportunities will increase.

We placed approximately $300 million of major capital projects into service during the first quarter of 2015. These projects included the expansion of our Houston Ship Channel LPG export terminal. We expect to complete construction and begin commercial operations of growth capital projects costing approximately $2.5 billion in the remainder of 2015. These projects include another significant expansion of our Houston Ship Channel LPG export terminal and various crude oil pipeline and storage products.

The following table summarizes our capital spending for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015		2014
Step 2 of Oiltanking acquisition (1)
Equity instruments (36,827,517 common units of Enterprise)	$	1,408.7	$	--
Capital spending for property, plant and equipment, net: (2)
Growth capital projects (3)		733.7		612.4
Sustaining capital projects (4)		59.5		83.0
Investments in unconsolidated affiliates		68.3		284.7
Total capital spending	$	2,270.2	$	980.1

(1) For a description of the acquisition of Oiltanking, see “Significant Recent Developments” within this Part I, Item 2. (2) 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 pipeline construction projects and production well tie-ins. Contributions in aid of construction costs were $19.6 million and $4.3 million for the three months ended March 31, 2015 and 2014, respectively. Growth and sustaining capital amounts presented in the table above are presented net of related contributions in aid of construction costs. (3) Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows. (4) Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings.

Fluctuations in our spending for growth capital projects and investments in unconsolidated affiliates are explained in large part by increases or decreases in spending on major expansion projects. Our most significant growth capital expenditures for the three months ended March 31, 2015 involved projects at our Houston LPG and ethane export terminals and Mont Belvieu complex. Fluctuations in spending for sustaining capital projects are explained in large part by the timing and cost of pipeline integrity and similar projects.

Capital spending for the first quarter of 2015 includes $1.4 billion of non-cash equity consideration we issued to complete Step 2 of the Oiltanking acquisition. Step 2 represented our acquisition of the noncontrolling interests in Oiltanking; therefore, approximately $1.4 billion of noncontrolling interests attributable to Oiltanking was reclassified to limited partners’ equity to reflect the February 2015 issuance of 36,827,517 Enterprise common units.

In total, capital spending for property, plant and equipment increased $97.8 million quarter-to-quarter primarily due to higher growth capital spending in the first quarter of 2015. Growth capital spending at our Houston Ship Channel LPG and ethane export facilities increased a combined $147.8 million quarter-to-quarter as work continued at both locations. We recently completed an expansion project at our Houston Ship Channel LPG export terminal that increased our ability to load cargoes of fully refrigerated, low-ethane propane from 7.5 MMBbls per month to approximately 9.0 MMBbls per month. Work continues at this marine terminal facility on another expansion project that will increase our loading capacity from 9.0 MMBbls per month to in excess of 16.0 MMBbls per month. This expansion project is expected to be in service by the end of 2015. Work also continues at our Houston Ship Channel ethane export facility, which we expect to begin operations in the third quarter of 2016.

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Growth capital spending at our Mont Belvieu complex increased $80.7 million quarter-to-quarter primarily due to construction of our propane dehydrogenation facility, which is expected to begin commercial operations during the fourth quarter of 2016. In addition, growth capital spending for our Rancho II crude oil pipeline and at our ECHO terminal increased a combined $64.8 million quarter-to-quarter. The Rancho II crude oil pipeline consists of 88 miles of pipeline extending from Sealy, Texas to our ECHO terminal. This pipeline is expected to be completed in July 2015. Current expansion projects at our ECHO terminal involve the construction of additional storage capacity and associated distribution pipelines. We expect to complete the expansion projects at ECHO in phases, with final completion expected in the second quarter of 2015.

Growth capital spending attributable to our ATEX pipeline, the Rocky Mountain expansion of our Mid-America Pipeline System and our Beaumont Refined Products Exports Terminal decreased a combined $182.1 million quarter-to-quarter. Expansion projects involving these assets were largely completed prior to the first quarter of 2015.

Investments in unconsolidated affiliates for the first quarter of 2015 decreased $216.4 million when compared to the first quarter of 2014 primarily due to completion of the Seaway Loop pipeline and SEKCO Oil Pipeline in July 2014.

Capital Spending Outlook

We currently expect our total capital spending for the remainder of 2015 to approximate $3.3 billion, which includes $320 million for sustaining capital expenditures. Our forecast of capital spending for the remainder of 2015 is based on our announced strategic operating and growth plans (through the filing date of this quarterly report), which are dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital spending due to factors beyond our control, such as adverse economic conditions, weather related issues and changes in supplier prices. Furthermore, our forecast of capital spending may change as a result of decisions made by management at a later date, which may include the addition of costs in connection with unforeseen acquisition opportunities.

Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be a significant factor in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we currently expect to make the forecast capital expenditures noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions.

Pipeline Integrity Costs

Our pipelines are subject to safety programs administered by the U.S. Department of Transportation (“DOT”). This federal agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (e.g., NGL, crude oil, refined products and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs.

The following table summarizes our pipeline integrity costs, including those attributable to DOT regulations, for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015		2014
Expensed	$	13.9	$	9.0
Capitalized		5.7		9.3
Total	$	19.6	$	18.3

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We expect the cost of our pipeline integrity program, regardless of whether such costs are capitalized or expensed, to approximate $96 million for the remainder of 2015. The cost of our pipeline integrity program was $99 million for the year ended December 31, 2014.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2014 Form 10-K. The following estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

depreciation methods and estimated useful lives of property, plant and equipment;

measuring recoverability of long-lived assets and equity method investments;

amortization methods and estimated useful lives of qualifying intangible assets;

methods we employ to measure the fair value of goodwill; and

revenue recognition policies and the use of estimates for revenue and expenses.

When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Other Items

Use of Non-GAAP Financial Measures

Gross operating margin . 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. For additional information regarding gross operating margin, see Note 11 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report.

The following table presents a reconciliation of non-GAAP total segment gross operating margin to GAAP operating income for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015			2014
Total segment gross operating margin	$	1,334.4		$	1,329.8
Adjustments to reconcile total segment gross operating margin to operating income:
Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin		(345.3	)		(301.4	)
Subtract impairment charges not reflected in gross operating margin		(33.3	)		(8.8	)
Add net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin		0.1			89.6
Subtract non-refundable deferred revenues attributable to shipper make-up rights on major new pipeline projects reflected in gross operating margin		(30.7	)		(23.3	)
Add subsequent recognition of deferred revenues attributable to make-up rights not reflected in gross operating margin		20.1			--
Subtract general and administrative costs not reflected in gross operating margin		(49.3	)		(53.2	)
Operating income	$	896.0		$	1,032.7

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Distributable cash flow . Our management compares the distributable cash flow we generate to the cash distributions we expect to pay our partners. Using this metric, management computes our distribution coverage ratio. Distributable cash flow is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. Distributable cash flow is also a quantitative standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. The GAAP measure most directly comparable to distributable cash flow is net cash flows provided by operating activities.

The following table presents a reconciliation of non-GAAP distributable cash flow to GAAP net cash flows provided by operating activities for the periods indicated (dollars in millions):

	For the Three Months Ended March 31,
	2015			2014
Distributable cash flow	$	1,029.7		$	1,087.0
Adjustments to reconcile distributable cash flow to net cash flows provided by operating activities:
Add sustaining capital expenditures reflected in distributable cash flow		50.7			78.3
Subtract cash proceeds from asset sales and insurance recoveries reflected in distributable cash flow		(0.5	)		(96.3	)
Net effect of changes in operating accounts not reflected in distributable cash flow		(139.0	)		342.5
Other, net		13.1			(7.4	)
Net cash flows provided by operating activities	$	954.0		$	1,404.1

Contractual Obligations

Our consolidated debt principal obligations at March 31, 2015 were approximately $21.62 billion compared to $21.39 billion at December 31, 2014. For information regarding the scheduled maturities of such debt, see “Liquidity and Capital Resources – Consolidated Debt” within this Part I, Item 2. See Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements under Part I, Item 1 of this quarterly report for additional information regarding our consolidated debt obligations.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial position, results of operations and cash flows.

Related Party Transactions

For information regarding our related party transactions, see Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

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Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

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 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.

Our exposures to market risk have not changed materially since those reported under Part II, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2014 Form 10-K.

We assess the risk associated with each of our derivative instrument portfolios using a sensitivity analysis model. This approach measures the change in fair value of the derivative instrument portfolio based on a hypothetical 10% change in the underlying interest rates or quoted market prices on a particular day. In addition to these variables, the fair value of each portfolio is influenced by changes in the notional amounts of the instruments outstanding and the discount rates used to determine the present values. The sensitivity analysis approach does not reflect the impact that the same hypothetical price movement would have on the hedged exposures to which they relate. Therefore, the impact on the fair value of a derivative instrument resulting from a change in interest rates or quoted market prices (as applicable) would normally be offset by a corresponding gain or loss on the hedged debt instrument, inventory value or forecasted transaction assuming:

§	the derivative instrument functions effectively as a hedge of the underlying risk;

§	the derivative instrument is not closed out in advance of its expected term; and

§	the hedged forecasted transaction occurs within the expected time period.

We routinely review the effectiveness of our derivative instrument portfolios in light of current market conditions. Accordingly, the nature and volume of our derivative instruments may change depending on the specific exposure being managed.

See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding our derivative instruments and 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.

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The following table summarizes our portfolio of commodity derivative instruments outstanding at March 31, 2015 (volume measures as noted):

	Volume (1)		Accounting
Derivative Purpose	Current (2)	Long-Term (2)	Treatment
Derivatives designated as hedging instruments:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (Bcf)	12.8	n/a	Cash flow hedge
Forecasted sales of NGLs (MMBbls) (3)	4.2	n/a	Cash flow hedge
Natural gas marketing:
Forecasted purchases of natural gas (Bcf)	11.1	n/a	Cash flow hedge
Forecasted sales of natural gas (Bcf)	2.1	n/a	Cash flow hedge
Natural gas storage inventory management activities (Bcf)	3.5	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)	18.5	n/a	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)	18.6	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)	1.1	n/a	Fair value hedge
Crude oil marketing:
Forecasted purchases of crude oil (MMBbls)	9.3	0.4	Cash flow hedge
Forecasted sales of crude oil (MMBbls)	11.5	0.4	Cash flow hedge
Derivatives not designated as hedging instruments:
Natural gas risk management activities (Bcf) (4,5)	89.5	10.0	Mark-to-market
NGL risk management activities (MMBbls) (5)	1.8	n/a	Mark-to-market
Crude oil risk management activities (MMBbls) (5)	5.5	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 June 2016, February 2016 and March 2018, respectively.
(3) Forecasted sales of NGL volumes under natural gas processing exclude 1.3 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
(4) Current volumes include 56.2 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.

At March 31, 2015, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory.

§	The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of forward contracts and derivative instruments.

The objective of our natural gas processing hedging program is to hedge an amount of gross margin associated with these activities. We achieve this objective by executing forward fixed-price sales of a portion of our expected equity NGL production using forward contracts and commodity derivative instruments. For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for plant thermal reduction, which is hedged by executing forward fixed-price purchases using forward contracts and derivative instruments.

§	The objective of our inventory hedging program 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.

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The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value of our natural gas marketing portfolio at the dates indicated (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2014			March 31, 2015				April 15, 2015
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	5.8		$	(0.7	)		$	(0.9	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			2.4			(0.9	)			(0.5	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			9.2			(0.6	)			(1.2	)

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value of our NGL marketing, refined products marketing and octane enhancement portfolios at the dates indicated (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2014			March 31, 2015				April 15, 2015
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	57.8		$	9.3			$	(6.3	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			47.5			(7.4	)			(24.0	)
Fair value assuming 10% decrease in underlying commodity prices	Asset			68.2			26.0				11.4

The following table shows the effect of hypothetical price movements (a sensitivity analysis) on the estimated fair value of our crude oil marketing portfolio at the dates indicated (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2014			March 31, 2015			April 15, 2015
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	15.6		$	16.1		$	(2.3	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			6.5			1.2			(15.3	)
Fair value assuming 10% decrease in underlying commodity prices	Asset			24.7			31.0			10.7

Item 4.

Controls and Procedures .

Disclosure Controls and Procedures

As of the end of the period covered by this quarterly report, our management carried out an evaluation, with the participation of our general partner’s chief executive officer, Michael A. Creel (our current principal executive officer), chief administrative officer, W. Randall Fowler, and chief financial officer, Bryan F. Bulawa, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Mr. Fowler and Mr. Bulawa are our principal financial officers. Based on this evaluation, as of the end of the period covered by this quarterly report, Mr. Creel, Mr. Fowler and Mr. Bulawa concluded:

(i)

that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow for timely decisions regarding required disclosures; and

(ii)

that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

We are continuing to evaluate and implement changes to the processes, policies and other applicable components of our internal control over financial reporting due to the consolidation of Oiltanking’s financial statements. Management continues to evaluate the effectiveness of our internal control procedures and the design of those control procedures as they relate to Oiltanking. In accordance with rules promulgated by the U.S. Securities and Exchange Commission, acquired businesses such as Oiltanking may be excluded from our assessment of

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internal control over financial reporting for one year while such businesses are being integrated with our legacy operations. We expect that this evaluation process will be completed during the fourth quarter of 2015.

We followed our normal accounting procedures and internal control processes when recording and disclosing the accounting impacts of the Oiltanking acquisition. In addition, management routinely reviews the results of operations of this acquired business prior to its consolidation with the results of operations of our other businesses.

There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the first quarter of 2015, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

The required certifications of Mr. Creel, Mr. Fowler and Mr. Bulawa under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are included as exhibits to this quarterly report (see Exhibits 31 and 32 under Part II, Item 6 of this quarterly report).

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings .

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

For additional information regarding our litigation matters, see “Litigation” under Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report, which subsection is incorporated by reference into this Part II, Item 1.

Item 1A. Risk Factors .

An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under “Risk Factors” set forth in Part I, Item 1A of our 2014 Form 10-K, in addition to other information in such annual report. The risk factors set forth in our 2014 Form 10-K are important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

The following table summarizes our repurchase activity during the three months ended March 31, 2015:

Period	Total Number of Units Purchased		Average Price Paid per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans		Maximum Number of Units That May Yet Be Purchased Under the Plans
February 2015 (1)		628,750	$	33.68		--		--
(1) Of the 1,852,746 restricted common units that vested in February 2015 and converted to common units, 628,750 units were sold back to us by employees to cover related withholding tax requirements.

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Item 3.

Defaults Upon Senior Securities.

None.

Item 4.

Mine Safety Disclosures .

Not applicable.

Item 5.

Other Information.

Disclosure Under Section 13(r) of the Securities Exchange Act of 1934

Under Section 13(r) of the Securities Exchange Act of 1934, as amended by the Iran Threat Reduction and Syria Human Rights Act of 2012, issuers are required to include certain disclosures in their periodic reports if they or any of their “affiliates” (as defined in Rule 12b-2 thereunder) have knowingly engaged in certain specified activities relating to Iran. Disclosure is required even where the activities are conducted outside the United States by non-U.S. affiliates in compliance with applicable law, and even if the activities are not covered or prohibited by U.S. law.

Dr. F. Christian Flach was named a director of our general partner in October 2014 in connection with the acquisition of Oiltanking. Dr. Flach is also a managing director of Oiltanking GmbH, which maintains a joint venture interest in Oiltanking Odfjell GmbH, which in turn owns a joint venture interest in the Exir Chemical Terminal (“ECT”) in Iran. This interest results from an investment dating back to 2002. Oiltanking GmbH currently has the contractual right to vote for the appointment of one member of ECT’s three-member board. Oiltanking GmbH provides no goods, services, technology, information or support to ECT and plays no role in the management or day-to-day operations of ECT.

Among other activities, ECT provides transit storage for naphtha originating in Iraq en route to Oman for a customer in the United Arab Emirates. ECT does not import or handle any products originated from Iran that are regulated under U.S., European Union or United Nations sanctions laws. ECT pays routine and standard charges (i) to the Petrochemical Special Economic Zone Organization (“Petzone”) for the use of pipelines and (ii) to Terminals and Tanks Petrochemical Co. (“TTPC”), which operates the berth. Petzone and TTPC are subsidiaries of the National Petrochemical Company, which is owned and controlled by the Government of Iran. As Oiltanking GmbH has no direct involvement in the day-to-day operations of ECT, we have no information regarding ECT’s intent to continue or not continue making the payments described above.

Oiltanking GmbH maintains an internal compliance program to ensure compliance with all applicable sanctions regimes, including sanctions laws maintained by the United States, European Union and United Nations. Although the existence of the routine payments described above may be reportable under Section 13(r), Oiltanking GmbH has informed us that neither it, nor any of its subsidiaries or affiliates, has engaged in any conduct that would be sanctionable under any of these legal regimes.

Amendment to Replacement Capital Covenants

On May 6, 2015, EPO and Enterprise Products Partners executed an amendment (the “Amendment”) to each of the following Replacement Capital Covenants: (i) the Replacement Capital Covenant, dated as of July 18, 2006, by EPO, in connection with EPO’s 8.375% Fixed/Floating Rate Junior Subordinated Notes due 2066, and as amended by the First Amendment thereto, dated as of August 25, 2006 (the “2006 Replacement Capital Covenant”); (ii) the Replacement Capital Covenant, dated as of May 24, 2007, by and among EPO and Enterprise Products Partners, in connection with EPO’s 7.034% Fixed/Floating Rate Junior Subordinated Notes due 2068 (the “2007 Replacement Capital Covenant”); and (iii) the Replacement Capital Covenant, dated as of October 27, 2009, by and among EPO and Enterprise Products Partners, in connection with EPO’s 7.000% Fixed/Floating Rate Junior Subordinated Notes due 2067 (the “2009 Replacement Capital Covenant” and, together with the 2006 Replacement Capital Covenant and the 2007 Replacement Capital Covenant, the “Replacement Capital Covenants”). The intent and effect of the Amendment is to recognize, for purposes of calculating qualified replacement capital under each

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Replacement Capital Covenant, the proceeds from the issuance by EPO, Enterprise Products Partners and their respective subsidiaries of certain securities, including but not limited to our common units, within a period of 365 days prior to the redemption or repurchase date or the notice of redemption or repurchase, as applicable under each of the Replacement Capital Covenants.

Copies of the 2006 Replacement Capital Covenant, the first amendment to the 2006 Replacement Capital Covenant, the 2007 Replacement Capital Covenant and the 2009 Replacement Capital Covenant are incorporated herein by reference to Exhibits 4.55, 4.56, 4.57 and 4.58, respectively, of this quarterly report on Form 10-Q. The foregoing description of the Amendment does not purport to be complete and is subject to and qualified in its entirety by reference to the full text of the Amendment, a copy of which is filed as Exhibit 4.59 hereto and incorporated by reference herein.

Item 6. Exhibits.

Exhibit Number	Exhibit*
2.1	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.2	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.3	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.4	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 21, 2004).
2.5	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
2.6	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29, 2009).
2.7	Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29, 2009).
2.8	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise ETE LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2010).
2.9	Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010).
2.10	Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010).

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2.11	Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011).
2.12	Contribution and Purchase Agreement, dated as of October 1, 2014, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc. and OTB Holdco, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2014).
2.13	Agreement and Plan of Merger, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPOT MergerCo LLC, Oiltanking Partners, L.P. and OTLP GP, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed November 12, 2014).
3.1	Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
3.2	Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
3.3	Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated November 22, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K filed November 23, 2010).
3.4	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 11, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 16, 2011).
3.5	Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 21, 2014 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 26, 2014).
3.6	Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC) (incorporated by reference to Exhibit 3.3 to Form S-1/A Registration Statement, Reg. No. 333-124320, filed by Enterprise GP Holdings L.P. on July 22, 2005).
3.7	Certificate of Amendment to Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC), filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.5 to Form 8-K filed November 23, 2010).
3.8	Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of September 7, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 8, 2011).
3.9	Company Agreement of Enterprise Products Operating LLC dated June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 8, 2007).
3.10	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.11	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1	Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed August 16, 2011).
4.2	Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.3	Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.4	Third Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8, 2007).

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4.5	Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 6, 2004).
4.6	Fourth Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6, 2004).
4.7	Fifth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed March 3, 2005).
4.8	Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
4.9	Eighth Supplemental Indenture, dated as of July 18, 2006, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.10	Ninth Supplemental Indenture, dated as of May 24, 2007, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed May 24, 2007).
4.11	Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
4.12	Eleventh Supplemental Indenture, dated as of September 4, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed September 5, 2007).
4.13	Thirteenth Supplemental Indenture, dated as of April 3, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.14	Sixteenth Supplemental Indenture, dated as of October 5, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.15	Seventeenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.16	Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.17	Nineteenth Supplemental Indenture, dated as of May 20, 2010, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 20, 2010).

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4.18	Twentieth Supplemental Indenture, dated as of January 13, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.19	Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.20	Twenty-Second Supplemental Indenture, dated as of February 15, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.25 to Form 10-Q filed May 10, 2012).
4.21	Twenty-Third Supplemental Indenture, dated as of August 13, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.22	Twenty-Fourth Supplemental Indenture, dated as of March 18, 2013, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.23	Twenty-Fifth Supplemental Indenture, dated as of February 12, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.24	Twenty-Sixth Supplemental Indenture, dated as of October 14, 2014, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.25	Form of Global Note representing $499.2 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
4.26	Form of Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.27	Form of Global Note representing $250.0 million principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed November 4, 2005).
4.28	Form of Global Note representing $250.0 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
4.29	Form of Junior Subordinated Note, including Guarantee (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.30	Form of Global Note representing $800.0 million principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 9, 2007).
4.31	Form of Global Note representing $700.0 million principal amount of 6.50% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
4.32	Form of Global Note representing $500.0 million principal amount of 5.25% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.33	Form of Global Note representing $600.0 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.34	Form of Global Note representing $349.7 million principal amount of 6.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit 4.6 to Form 8-K filed October 28, 2009).

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4.35	Form of Global Note representing $399.6 million principal amount of 7.55% Senior Notes due 2038 with attached Guarantee (incorporated by reference to Exhibit 4.7 to Form 8-K filed October 28, 2009).
4.36	Form of Global Note representing $285.8 million principal amount of 7.000% Junior Subordinated Notes due 2067 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 8-K filed October 28, 2009).
4.37	Form of Global Note representing $400.0 million principal amount of 3.70% Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
4.38	Form of Global Note representing $1.0 billion principal amount of 5.20% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
4.39	Form of Global Note representing $600.0 million principal amount of 6.45% Senior Notes due 2040 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
4.40	Form of Global Note representing $750.0 million principal amount of 3.20% Senior Notes due 2016 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 13, 2011).
4.41	Form of Global Note representing $750.0 million principal amount of 5.95% Senior Notes due 2041 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 13, 2011).
4.42	Form of Global Note representing $650.0 million principal amount of 4.05% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 24, 2011).
4.43	Form of Global Note representing $600.0 million principal amount of 5.70% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 24, 2011).
4.44	Form of Global Note representing $750.0 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (included in Exhibit 4.25 above).
4.45	Form of Global Note representing $650.0 million principal amount of 1.25% Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 13, 2012).
4.46	Form of Global Note representing $1.1 billion principal amount of 4.45% Senior Notes due 2043 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 13, 2012).
4.47	Form of Global Note representing $1.25 billion principal amount of 3.35% Senior Notes due 2023 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed March 18, 2013).
4.48	Form of Global Note representing $1.0 billion principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed March 18, 2013).
4.49	Form of Global Note representing $850.0 million principal amount of 3.90% Senior Notes due 2024 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed February 12, 2014).
4.50	Form of Global Note representing $1.15 billion principal amount of 5.10% Senior Notes due 2045 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed February 12, 2014).
4.51	Form of Global Note representing $800.0 million principal amount of 2.55% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 14, 2014).
4.52	Form of Global Note representing $1.15 billion principal amount of 3.75% Senior Notes due 2025 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 14, 2014).
4.53	Form of Global Note representing $400.0 million principal amount of 4.95% Senior Notes due 2054 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 14, 2014).

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4.54	Form of Global Note representing $400.0 million principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 14, 2014).
4.55	Replacement Capital Covenant, dated July 18, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to Form 8-K filed July 19, 2006).
4.56	First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
4.57	Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to Form 8-K filed May 24, 2007).
4.58	Replacement Capital Covenant, dated October 27, 2009, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).
4.59#	Amendment to Replacement Capital Covenants, dated May 6, 2015, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein.
4.60	Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.2 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
4.61	Second Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P. on August 14, 2002).
4.62	Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006).
4.63	Fourth Supplemental Indenture, dated June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.64	Sixth Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.12 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.65	Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.66	Eighth Supplemental Indenture, dated October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).

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4.67	Full Release of Guarantee, dated November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.64 to Form 10-K filed on March 1, 2010).
4.68	Indenture, dated May 14, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 99.1 of the Form 8-K filed by TEPPCO Partners, L.P. on May 15, 2007).
4.69	First Supplemental Indenture, dated May 18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007).
4.70	Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Existing Subsidiary Guarantors, TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as New Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
4.71	Third Supplemental Indenture, dated as of October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
4.72	Full Release of Guarantee, dated as of November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.70 to Form 10-K filed on March 1, 2010).
4.73	Registration Rights Agreement by and between Enterprise Products Partners L.P. and Oiltanking Holding Americas, Inc. dated as of October 1, 2014 (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 1, 2014).
10.1	Eighth Amended and Restated Administrative Services Agreement, effective as of February 13, 2015, by and among Enterprise Products Company, EPCO Holdings, Inc., Enterprise Products Holdings LLC, Enterprise Products Partners L.P., Enterprise Products OLPGP, Inc., Enterprise Products Operating LLC and the Oiltanking Parties named therein (incorporated by reference to Exhibit 10.1 to Form 8-K filed on February 13, 2015).
10.2***	Amendment Letter to Restricted Unit and Phantom Unit Grant Awards under the Enterprise Products 1998 Long-Term Incentive Plan and/or the 2008 Enterprise Products Long-Term Incentive Plan for awards issued before February 18, 2015 (incorporated by reference to Exhibit 10.7 to the Form 10-K filed on March 2, 2015).
10.3***	Form of Employee Phantom Unit Grant Award under the 2008 Enterprise Products Long-Term Incentive Plan for awards issued on or after February 18, 2015 (incorporated by reference to Exhibit 10.8 to the Form 10-K filed on March 2, 2015).
12.1#	Computation of ratio of earnings to fixed charges for the three months ended March 31, 2015 and each of the five years ended December 31, 2014, 2013, 2012, 2011 and 2010.
31.1#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2015.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2015.
31.3#	Sarbanes-Oxley Section 302 certification of Bryan F. Bulawa for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2015.
32.1#	Sarbanes-Oxley Section 906 certification of Michael A. Creel for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2015.

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32.2#	Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2015.
32.3#	Sarbanes-Oxley Section 906 certification of Bryan F. Bulawa for Enterprise Products Partners L.P.’s quarterly report on Form 10-Q for the three months ended March 31, 2015.
101.CAL#	XBRL Calculation Linkbase Document
101.DEF#	XBRL Definition Linkbase Document
101.INS#	XBRL Instance Document
101.LAB#	XBRL Labels Linkbase Document
101.PRE#	XBRL Presentation Linkbase Document
101.SCH#	XBRL Schema Document

Delaware		76-0568219
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

Large accelerated filer 	Accelerated filer 
Non-accelerated filer  (Do not check if a smaller reporting company)	Smaller reporting company 

	March 31, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	81.1		$	74.4
Restricted cash		28.2			--
Accounts receivable – trade, net of allowance for doubtful accounts of $14.3 at March 31, 2015 and $13.9 at December 31, 2014		2,985.1			3,823.0
Accounts receivable – related parties		3.4			2.8
Inventories		855.4			1,014.2
Prepaid and other current assets		481.6			576.3
Total current assets		4,434.8			5,490.7
Property, plant and equipment, net		30,367.6			29,881.6
Investments in unconsolidated affiliates		3,064.9			3,042.0
Intangible assets, net of accumulated amortization of $1,285.1 at March 31, 2015 and $1,246.3 at December 31, 2014 (see Note 8)		2,804.1			4,302.1
Goodwill (see Note 8)		5,654.0			4,199.9
Other assets		179.9			184.4
Total assets	$	46,505.3		$	47,100.7

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 9)	$	1,399.8		$	2,206.4
Accounts payable – trade		704.5			773.8
Accounts payable – related parties		49.3			118.9
Accrued product payables		3,085.2			3,853.3
Accrued interest		180.0			335.5
Other current liabilities		457.1			585.8
Total current liabilities		5,875.9			7,873.7
Long-term debt (see Note 9)		20,192.2			19,157.4
Deferred tax liabilities		68.0			66.6
Other long-term liabilities		311.1			310.8
Commitments and contingencies (see Note 14)
Equity:
Partners’ equity:
Limited partners:
Common units (1,988,553,334 units outstanding at March 31, 2015 and 1,937,324,817 units outstanding at December 31, 2014)		20,098.9			18,304.8
Accumulated other comprehensive loss		(263.2	)		(241.6	)
Total partners’ equity		19,835.7			18,063.2
Noncontrolling interests (see Note 10)		222.4			1,629.0
Total equity		20,058.1			19,692.2
Total liabilities and equity	$	46,505.3		$	47,100.7

	For the Three Months Ended March 31,
	2015			2014

Net income	$	650.6		$	806.7
Other comprehensive income (loss):
Cash flow hedges:
Commodity derivative instruments:
Changes in fair value of cash flow hedges		30.8			(9.2	)
Reclassificati on of losses (gains) to ne t income		(61.1	)		16.0
Interest rate derivative instruments:
Reclassification of losses to net income		8.7			7.9
Total other comprehens ive income (loss)		(21.6	)		14.7
Comprehensive income		629.0			821.4
Comprehensive income attributable to noncontrolling interests		(14.5	)		(7.9	)
Comprehensive income attributable to limited partners	$	614.5		$	813.5

	For the Three Months Ended March 31,
	2015			2014
Operating activities:
Net income	$	650.6		$	806.7
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion		367.4			319.9
Non-cash asset impairment charges (see Note 4)		33.3			8.8
Equity in income of unconsolidated affiliates		(89.2	)		(56.5	)
Distributions received from unconsolidated affiliates		134.4			71.7
Net gains attributable to asset sales and insurance recoveries (see Note 15)		(0.1	)		(89.6	)
Deferred income tax expense		1.5			0.2
Changes in fair market value of derivative instruments		(4.6	)		(7.8	)
Net effect of changes in operating accounts (see Note 15)		(139.0	)		342.5
Other operating activities		(0.3	)		8.2
Net cash flows provided by operating activities		954.0			1,404.1
Investing activities:
Capital expenditures		(812.8	)		(699.7	)
Contributions in aid of construction costs		19.6			4.3
Decrease (increase) in restricted cash		(28.2	)		22.3
Investments in unconsolidated affiliates		(68.3	)		(284.7	)
Proceeds from asset sales and insurance recoveries (see Note 15)		0.5			96.3
Other investing activities		0.1			--
Cash used in investing activities		(889.1	)		(861.5	)
Financing activities:
Borrowings under debt agreements		9,182.5			4,181.5
Repayments of debt		(8,953.2	)		(3,160.0	)
Debt issuance costs		(0.1	)		(15.9	)
Cash distributions paid to limited partners (see Note 10)		(703.8	)		(639.2	)
Cash payments made in connection with distribution equivalent rights		(1.2	)		--
Cash distributions paid to noncontrolling interests		(16.5	)		(8.0	)
Cash contributions from noncontrolling interests		4.0			--
Net cash proceeds from the issuance of common units		468.4			83.0
Other financing activities		(38.3	)		(52.5	)
Cash provided by (used in) financing activities		(58.2	)		388.9
Net change in cash and cash equivalents		6.7			931.5
Cash and cash equivalents, January 1		74.4			56.9
Cash and cash equivalents, March 31	$	81.1		$	988.4

		Page No.
PART I. FINANCIAL INFORMATION.
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated Balance Sheets	2
	Unaudited Condensed Statements of Consolidated Operations	3
	Unaudited Condensed Statements of Consolidated Comprehensive Income	4
	Unaudited Condensed Statements of Consolidated Cash Flows	5
	Unaudited Condensed Statements of Consolidated Equity	6
	Notes to Unaudited Condensed Consolidated Financial Statements:
	1. Partnership Operations, Organization and Basis of Presentation	7
	2. General Accounting and Disclosure Matters	8
	3. Equity-based Awards	10
	4. Derivative Instruments, Hedging Activities and Fair Value Measurements	13
	5. Inventories	19
	6. Property, Plant and Equipment	20
	7. Investments in Unconsolidated Affiliates	21
	8. Intangible Assets and Goodwill	23
	9. Debt Obligations	25
	10. Equity and Distributions	26
	11. Business Segments	29
	12. Related Party Transactions	32
	13. Earnings Per Unit	34
	14. Commitments and Contingencies	34
	15. Supplemental Cash Flow Information	36
	16. Condensed Consolidating Financial Information	37
	17. Subsequent Event	43
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	44
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	65
Item 4.	Controls and Procedures.	67

PART II. OTHER INFORMATION.
Item 1.	Legal Proceedings.	68
Item 1A.	Risk Factors.	68
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	68
Item 3.	Defaults Upon Senior Securities.	69
Item 4.	Mine Safety Disclosures.	69
Item 5.	Other Information.	69
Item 6.	Exhibits.	70

Signatures		78

	Partners’ Equity
	Limited Partners			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
Balance, December 31, 2014	$	18,304.8		$	(241.6	)	$	1,629.0		$	19,692.2
Net income		636.1			--			14.5			650.6
Cash distributions paid to limited partners		(703.8	)		--			--			(703.8	)
Cash payments made in connection with distribution equivalent rights		(1.2	)		--			--			(1.2	)
Cash distributions paid to noncontrolling interests		--			--			(16.5	)		(16.5	)
Cash contributions from noncontrolling interests		--			--			4.0			4.0
Common units issued in connection with Step 2 of Oiltanking acquisition		1,408.7			--			(1,408.7	)		--
Net cash proceeds from the issuance of common units		468.4			--			--			468.4
Amortization of fair value of equity-based awards		23.3			--			--			23.3
Cash flow hedges		--			(21.6	)		--			(21.6	)
Other		(37.4	)		--			0.1			(37.3	)
Balance, March 31, 2015	$	20,098.9		$	(263.2	)	$	222.4		$	20,058.1

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units at December 31, 2014		4,229,790		$	26.96
Vested		(1,852,746	)	$	25.89
Forfeited		(84,700	)	$	27.16
Restricted common units at March 31, 2015		2,292,344		$	27.82

(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

	Number of Units (1)			Weighted- Average Strike Price (dollars/unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (2)
Unit option awards at December 31, 2014		1,270,000		$	16.14
Exercised		(940,000	)	$	16.14
Unit option awards at March 31, 2015		330,000		$	16.14		0.8	$	5.5

(1) All of the unit option awards outstanding at March 31, 2015 were exercisable. None of the unit option awards outstanding at December 31, 2014 were exercisable. (2) Aggregate intrinsic value reflects fully vested unit option awards at the dates indicated.

	Number of Units			Weighted- Average Grant Date Fair Value per Unit (1)
Phantom unit awards at December 31, 2014		3,342,390		$	33.13
Granted (2)		3,446,240		$	34.05
Vested		(786,890	)	$	33.04
Forfeited		(78,204	)	$	33.16
Phantom unit awards at March 31, 2015		5,923,536		$	33.67

(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 2015 was $117.3 million based on a grant date market price of our common units ranging from $34.04 to $34.40 per unit. An estimated annual forfeiture rate of 3.5% was applied to these awards.

	Asset Derivatives						Liability Derivatives
	March 31, 2015			December 31, 2014			March 31, 2015			December 31, 2014
	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
Commodity derivatives	Other current assets	$	123.9	Other current assets	$	217.9	Other current liabilities	$	100.3	Other current liabilities	$	145.3
Commodity derivatives	Other assets		0.7	Other assets		--	Other liabilities		0.9	Other liabilities		--
Total commodity derivatives		$	124.6		$	217.9		$	101.2		$	145.3

Derivatives not designated as hedging instruments
Commodity derivatives	Other current assets	$	7.8	Other current assets	$	8.1	Other current liabilities	$	5.5	Other current liabilities	$	0.7
Commodity derivatives	Other assets		0.3	Other assets		0.6	Other liabilities		1.3	Other liabilities		1.4
Total commodity derivatives		$	8.1		$	8.7		$	6.8		$	2.1

	Offsetting of Financial Assets and Derivative Assets
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Amounts of Assets Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet												Amounts That Would Have Been Presented On Net Basis
	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				Cash Collateral Paid				Amounts That Would Have Been Presented On Net Basis
	(i)			(ii)			(iii) = (i) – (ii)			(iv)												(v) = (iii) + (iv)
As of March 31, 2015:
Commodity derivatives		$	132.7		$	--		$	132.7		$	(91.2	)		$	--			$	(28.4	)		$	13.1
As of December 31, 2014:
Commodity derivatives		$	226.6		$	--		$	226.6		$	(147.3	)		$	(23.9	)		$	--			$	55.4

	Offsetting of Financial Liabilities and Derivative Liabilities
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Amounts of Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet							Amounts That Would Have Been Presented On Net Basis
	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 March 31, 2015:
Commodity derivatives		$	108.0		$	--		$	108.0		$	(91.2	)		$	--		$	16.8
As of December 31, 2014:
Commodity derivatives		$	147.4		$	--		$	147.4		$	(147.3	)		$	--		$	0.1

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Derivative
		For the Three Months Ended March 31,
		2015		2014
Interest rate derivatives	Interest expense	$	--	$	(2.9	)
Commodity derivatives	Revenue		0.7		(0.4	)
Total		$	0.7	$	(3.3	)

Derivatives in Fair Value Hedging Relationships	Location	Gain (Loss) Recognized in Income on Hedged Item
		For the Three Months Ended March 31,
		2015		2014
Interest rate derivatives	Interest expense	$	--	$	2.9
Commodity derivatives	Revenue		8.6		(1.4	)
Total		$	8.6	$	1.5

Derivatives in Cash Flow Hedging Relationships	Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative (Effective Portion)
	For the Three Months Ended March 31,
	2015			2014
Commodity derivatives – Revenue (1)	$	32.6		$	(10.7	)
Commodity derivatives – Operating costs and expenses (1)		(1.8	)		1.5
Total	$	30.8		$	(9.2	)

(1) The fair value of these derivative instruments will be reclassified to their respective locations on the Unaudited Condensed 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 Three Months Ended March 31,
		2015			2014
Interest rate derivatives	Interest expense	$	(8.7	)	$	(7.9	)
Commodity derivatives	Revenue		61.1			(16.9	)
Commodity derivatives	Operating costs and expenses		--			0.9
Total		$	52.4		$	(23.9	)

Derivatives Not Designated as Hedging Instruments	Location	Gain (Loss) Recognized in Income on Derivative
		For the Three Months Ended March 31,
		2015			2014
Commodity derivatives	Revenue	$	(0.4	)	$	(21.0	)

	March 31, 2015 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	$	19.9	$	112.4	$	0.4	$	132.7

Financial liabilities:
Liquidity Option Agreement	$	--	$	--	$	119.4	$	119.4
Commodity derivatives		10.9		94.8		2.3		108.0
Total	$	10.9	$	94.8	$	121.7	$	227.4

	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

	Fair Value
	Financial Assets		Financial Liabilities		Valuation Techniques	Unobservable Input	Range
Commodity derivatives – Crude oil	$	0.4	$	0.8	Discounted cash flow	Forward commodity prices	$47.63-$57.73/barrel
Commodity derivatives – Natural gasoline		--		1.5	Discounted cash flow	Forward commodity prices	$1.12-$1.13/gallon
Total	$	0.4	$	2.3

				Fair Value Measurements Using
	Carrying Value at March 31, 2015			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		$	--		$	--		$	--		$	--		$	33.1
Impairment of long-lived assets to be disposed of by sale			0.6			--			--			0.6			0.2
Total														$	33.3

				Fair Value Measurements Using
	Carrying Value at March 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		$	--		$	--		$	--		$	--		$	3.8
Impairment of long-lived assets to be disposed of by sale			0.1			--			--			0.1			5.0
Total														$	8.8

	March 31, 2015		December 31, 2014
NGLs	$	490.8	$	579.1
Petrochemicals and refined products		218.5		295.6
Crude oil		130.5		97.8
Natural gas		15.6		41.7
Total	$	855.4	$	1,014.2

	Estimated Useful Life in Years	March 31, 2015		December 31, 2014
Plants, pipelines and facilities (1)	3-45 (6)	$	31,153.8	$	30,834.9
Underground and other storage facilities (2)	5-40 (7)		2,609.3		2,584.2
Platforms and facilities (3)	20-31		659.7		659.7
Transportation equipment (4)	3-10		158.7		154.2
Marine vessels (5)	15-30		803.1		796.4
Land			260.9		262.6
Construction in progress			3,196.6		2,754.7
Total			38,842.1		38,046.7
Less accumulated depreciation			8,474.5		8,165.1
Property, plant and equipment, net		$	30,367.6	$	29,881.6

(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.

ARO liability balance, December 31, 2014	$	98.3
Liabilities incurred		--
Liabilities settled		(3.3	)
Revisions in estimated cash flows		11.0
Accretion expense		1.6
ARO liability balance, March 31, 2015	$	107.6

	Ownership Interest at March 31, 2015	March 31, 2015		December 31, 2014
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.	13.1%	$	27.0	$	27.7
K/D/S Promix, L.L.C.	50%		37.6		38.5
Baton Rouge Fractionators LLC	32.2%		18.6		18.8
Skelly-Belvieu Pipeline Company, L.L.C.	50%		39.5		40.1
Texas Express Pipeline LLC	35%		349.6		349.3
Texas Express Gathering LLC	45%		37.6		37.9
Front Range Pipeline LLC	33.3%		171.7		170.0
Onshore Natural Gas Pipelines & Services:
White River Hub, LLC	50%		23.1		23.2
Onshore Crude Oil Pipelines & Services:
Seaway Crude Pipeline Company LLC	50%		1,430.1		1,431.2
Eagle Ford Pipeline LLC	50%		350.5		336.5
Eagle Ford Terminals Corpus Christi LLC (1)	50%		17.3		--
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36%		29.2		31.8
Cameron Highway Oil Pipeline Company	50%		198.1		201.3
Deepwater Gateway, L.L.C.	50%		78.9		79.6
Neptune Pipeline Company, L.L.C.	25.7%		33.7		34.9
Southeast Keathley Canyon Pipeline Company L.L.C.	50%		147.6		146.1
Petrochemical & Refined Products Services:
Baton Rouge Propylene Concentrator, LLC	30%		6.1		6.5
Centennial Pipeline LLC (“Centennial”)	50%		66.3		66.1
Other	Various		2.4		2.5
Total		$	3,064.9	$	3,042.0

(1) New joint venture formed with Plains Marketing, L.P. in March 2015 to construct and operate a marine terminal that will handle crude oil delivered by Eagle Ford Pipeline LLC.

	March 31, 2015							December 31, 2014
	Gross Value		Accumulated Amortization			Carrying Value		Gross Value		Accumulated Amortization			Carrying Value
NGL Pipelines & Services:
Customer relationship intangibles	$	340.8	$	(187.2	)	$	153.6	$	340.8	$	(183.2	)	$	157.6
Contract-based intangibles		277.7		(182.2	)		95.5		277.7		(178.7	)		99.0
IDRs (1)		--		--			--		432.6		--			432.6
Segment total		618.5		(369.4	)		249.1		1,051.1		(361.9	)		689.2
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles		1,163.6		(314.9	)		848.7		1,163.6		(308.9	)		854.7
Contract-based intangibles		466.0		(351.7	)		114.3		466.0		(347.8	)		118.2
Segment total		1,629.6		(666.6	)		963.0		1,629.6		(656.7	)		972.9
Onshore Crude Oil Pipelines & Services:
Customer relationship intangibles		1,108.0		(10.3	)		1,097.7		1,108.0		(7.7	)		1,100.3
Contract-based intangibles		281.4		(27.6	)		253.8		281.4		(13.5	)		267.9
IDRs (1)		--		--			--		855.4		--			855.4
Segment total		1,389.4		(37.9	)		1,351.5		2,244.8		(21.2	)		2,223.6
Offshore Pipelines & Services:
Customer relationship intangibles		195.8		(157.2	)		38.6		195.8		(154.9	)		40.9
Contract-based intangibles		1.2		(0.5	)		0.7		1.2		(0.5	)		0.7
Segment total		197.0		(157.7	)		39.3		197.0		(155.4	)		41.6
Petrochemical & Refined Products Services:
Customer relationship intangibles		198.4		(44.6	)		153.8		198.4		(43.3	)		155.1
Contract-based intangibles		56.3		(8.9	)		47.4		56.3		(7.8	)		48.5
IDRs (1)		--		--			--		171.2		--			171.2
Segment total		254.7		(53.5	)		201.2		425.9		(51.1	)		374.8
Total all segments	$	4,089.2	$	(1,285.1	)	$	2,804.1	$	5,548.4	$	(1,246.3	)	$	4,302.1

(1) At December 31, 2014, we had indefinite-lived intangible assets outstanding with a carrying value of $1.46 billion recorded in connection with our acquisition of the Oiltanking IDRs in October 2014. The IDRs represented contractual rights to future cash incentive distributions to be paid by Oiltanking. In February 2015 (following completion of Step 2 of the Oiltanking acquisition), the Oiltanking IDRs were cancelled and the carrying value of the IDRs were reclassified to 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, 2014	$	2,180.4	$	296.3	$	859.9	$	82.0	$	781.3	$	4,199.9
Reclassification of Oiltanking IDR balances to goodwill in connection with the cancellation of such rights in February 2015		432.6		--		850.7		--		170.8		1,454.1
Balance at March 31, 2015	$	2,613.0	$	296.3	$	1,710.6	$	82.0	$	952.1	$	5,654.0

	March 31, 2015			December 31, 2014
EPO senior debt obligations:
Commercial Paper Notes, variable-rates	$	1,388.0		$	906.5
Senior Notes I, 5.00% fixed-rate, due March 2015		--			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			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			850.0
Senior Notes MM, 3.75% fixed-rate, due February 2025		1,150.0			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			1,400.0
Senior Notes KK, 5.10% fixed-rate, due February 2045		1,150.0			1,150.0
Senior Notes NN, 4.95% fixed-rate, due October 2054		400.0			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		20,088.0			19,856.5
EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066 (1)		550.0			550.0
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067 (2)		285.8			285.8
EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068 (3)		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		21,620.7			21,389.2
Other, non-principal amounts		(28.7	)		(25.4	)
Less current maturities of debt (4)		(1,399.8	)		(2,206.4	)
Total long-term debt	$	20,192.2		$	19,157.4

(1) Fixed rate of 8.375% through August 1, 2016; thereafter, variable rate based on 3-month LIBOR plus 3.7075%.
(2) Fixed rate of 7.0% through September 1, 2017; thereafter, variable rate based on 3-month LIBOR plus 2.7775%.
(3) 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%.
(4) We expect to refinance the current maturities of our debt obligations at or prior to their maturity. Long-term and current maturities of debt reflect the classification of such obligations at March 31, 2015, after taking into consideration the long-term refinancing of Senior Notes X and Commercial Paper Notes using proceeds from our senior notes offering in May 2015 (see Note 17).

	Range of Interest Rates Paid	Weighted-Average Interest Rate Paid
Commercial Paper Notes	0.35% to 0.78%	0.59%
EPO $3.5 Billion Multi-Year Revolving Credit Facility	1.15% to 3.25%	1.26%

	Common Units (Unrestricted)			Restricted Common Units			Total Common Units
Number of units outstanding at December 31, 2014		1,933,095,027			4,229,790			1,937,324,817
Common units issued in connection with at-the-market program		12,350,761			--			12,350,761
Common units issued in connection with DRIP and EUPP		1,940,832			--			1,940,832
Common units issued in connection with Step 2 of Oiltanking acquisition		36,827,517			--			36,827,517
Common units issued in connection with the vesting and exercise of unit options		291,250			--			291,250
Common units issued in connection with the vesting of phantom unit awards		519,247			--			519,247
Common units issued in connection with the vesting of restricted common unit awards		1,852,746			(1,852,746	)		--
Forfeiture of restricted common unit awards		--			(84,700	)		(84,700	)
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards		(628,750	)		--			(628,750	)
Other		12,360			--			12,360
Number of units outstanding at March 31, 2015		1,986,260,990			2,292,344			1,988,553,334

	Gains (Losses) on Cash Flow Hedges
	Commodity Derivative Instruments			Interest Rate Derivative Instruments			Other		Total
Balance, December 31, 2014	$	69.9		$	(314.8	)	$	3.3	$	(241.6	)
Other comprehensive income before reclassifications		30.8			--			--		30.8
Amounts reclassified from accumulated other comprehensive loss (income)		(61.1	)		8.7			--		(52.4	)
Total other comprehensive income (loss)		(30.3	)		8.7			--		(21.6	)
Balance, March 31, 2015	$	39.6		$	(306.1	)	$	3.3	$	(263.2	)

	Distribution Per Common Unit		Record Date	Payment Date
2014:
1st Quarter	$	0.3550	4/30/2014	5/7/2014
2015:
1st Quarter	$	0.3750	4/30/2015	5/7/2015

	Reportable Business Segments
	NGL Pipelines & Services		Onshore Natural Gas Pipelines & Services		Onshore Crude Oil Pipelines & Services		Offshore Pipelines & Services		Petrochemical & Refined Products Services			Adjustments and Eliminations			Consolidated Total
Revenues from third parties:
Three months ended March 31, 2015	$	2,674.8	$	730.9	$	2,677.0	$	34.6	$	1,349.1		$	--		$	7,466.4
Three months ended March 31, 2014		5,173.7		1,200.0		4,935.4		34.7		1,530.6			--			12,874.4
Revenues from related parties:
Three months ended March 31, 2015		1.5		3.0		1.0		0.6		--			--			6.1
Three months ended March 31, 2014		5.8		4.6		22.9		2.2		--			--			35.5
Intersegment and intrasegment revenues:
Three months ended March 31, 2015		2,443.1		170.0		1,277.1		0.4		285.6			(4,176.2	)		--
Three months ended March 31, 2014		3,861.0		309.4		2,550.7		2.3		437.0			(7,160.4	)		--
Total revenues:
Three months ended March 31, 2015		5,119.4		903.9		3,955.1		35.6		1,634.7			(4,176.2	)		7,472.5
Three months ended March 31, 2014		9,040.5		1,514.0		7,509.0		39.2		1,967.6			(7,160.4	)		12,909.9
Equity in income (loss) of unconsolidated affiliates:
Three months ended March 31, 2015		11.6		0.9		59.9		20.2		(3.4	)		--			89.2
Three months ended March 31, 2014		1.4		0.9		42.7		11.1		0.4			--			56.5
Gross operating margin:
Three months ended March 31, 2015		695.2		204.5		214.0		46.1		174.6			--			1,334.4
Three months ended March 31, 2014		780.0		220.4		159.7		39.3		130.4			--			1,329.8
Property, plant and equipment, net: (see Note 6)
At March 31, 2015		11,775.8		8,839.5		2,382.8		1,130.1		3,042.8			3,196.6			30,367.6
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
Investments in unconsolidated affiliates: (see Note 7)
At March 31, 2015		681.6		23.1		1,797.9		487.5		74.8			--			3,064.9
At December 31, 2014		682.3		23.2		1,767.7		493.7		75.1			--			3,042.0
Intangible assets, net: (see Note 8)
At March 31, 2015		249.1		963.0		1,351.5		39.3		201.2			--			2,804.1
At December 31, 2014		689.2		972.9		2,223.6		41.6		374.8			--			4,302.1
Goodwill: (see Note 8)
At March 31, 2015		2,613.0		296.3		1,710.6		82.0		952.1			--			5,654.0
At December 31, 2014		2,180.4		296.3		859.9		82.0		781.3			--			4,199.9
Segment assets:
At March 31, 2015		15,319.5		10,121.9		7,242.8		1,738.9		4,270.9			3,196.6			41,890.6
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