ENTERPRISE PRODUCTS PARTNERS L.P. - Annual Report: 2014 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Section I.01

FORM 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___.

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

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

	1100 LOUISIANA STREET, 10^th FLOOR, HOUSTON, TEXAS 77002
	(Address of Principal Executive Offices) (Zip Code)

	(713) 381-6500
	(Registrant's Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Common Units

Name of Each Exchange On Which Registered

New York Stock Exchange

Securities to be registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

The aggregate market value of the partnership's common units held by non-affiliates at June 30, 2014 (the last business day of the registrant's most recently completed second fiscal quarter) was $46.77 billion based on a closing price on that date of $39.15 per common unit on the New York Stock Exchange Composite ticker tape. There were 1,937,592,017 common units outstanding at January 31, 2015.

ENTERPRISE PRODUCTS PARTNERS L.P.

TABLE OF CONTENTS

		Page
		Number
PART I
Item 1 and 2.	Business and Properties.	2
Item 1A.	Risk Factors.	46
Item 1B.	Unresolved SEC Staff Comments.	64
Item 3.	Legal Proceedings.	64
Item 4.	Mine Safety Disclosures.	65

PART II
Item 5.	Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.	66
Item 6.	Selected Financial Data.	68
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	70
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	113
Item 8.	Financial Statements and Supplementary Data.	116
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	116
Item 9A.	Controls and Procedures.	116
Item 9B.	Other Information.	119

PART III
Item 10.	Directors, Executive Officers and Partnership Governance.	119
Item 11.	Executive Compensation.	127
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.	138
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	141
Item 14.	Principal Accountant Fees and Services.	144

PART IV
Item 15.	Exhibits and Financial Statement Schedules.	145

Signatures		154

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KEY REFERENCES USED IN THIS REPORT

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 35.3% of our limited partner interests at December 31, 2014.

References to "Oiltanking" mean Oiltanking Partners L.P. References to "Oiltanking GP" mean OTLP GP, LLC, the general partner of Oiltanking. On October 1, 2014, we acquired Oiltanking GP and the related incentive distribution rights ("IDRs"), 15,899,802 common units and 38,899,802 subordinated units of Oiltanking from Oiltanking Holding Americas, Inc. and its affiliates (collectively, "OTA").

As generally used in the energy industry and in this annual 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 annual report on Form 10-K for the year ended December 31, 2014 (our "annual report") 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," "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 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 Part I, Item 1A of this annual report. 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 annual report speak only as of the 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.

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PART I

Item 1 and 2. Business and Properties.

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.

§	natural gas gathering, treating, processing, transportation and storage;

§	NGL transportation, fractionation, storage, and import and export terminals (including liquefied petroleum gas or "LPG");

§	crude oil gathering, transportation, storage and terminals;

§	offshore production platforms;

§	petrochemical and refined products transportation, storage and terminals, and related services; and

§	a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems and in the Gulf of Mexico.

Our assets include approximately 51,300 miles of onshore and offshore pipelines; 225 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 export terminals, a refined products export terminal, and octane enhancement and high-purity isobutylene production facilities.

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. Our principal executive offices are located at 1100 Louisiana Street, 10^th Floor, Houston, Texas 77002, our telephone number is (713) 381-6500 and our website address is www.enterpriseproducts.com.

Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the "ASA") or by other service providers. As of February 1, 2015, there were approximately 6,900 EPCO personnel who spend all or a substantial portion of their time engaged in our business. For additional information regarding the ASA, see "EPCO ASA" under Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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Business Strategy

Our business strategies are to:

capitalize on expected increases in the production of natural gas, NGLs and crude oil from development activities in various domestic production basins (e.g., the Rocky Mountains, Mid-Continent, Northeast, U.S. Gulf Coast and deepwater Gulf of Mexico), including associated shale plays such as the Barnett, Eagle Ford, Permian, Haynesville, Marcellus, Mancos and Utica Shales;

§	capitalize on expected demand growth for natural gas, NGLs, crude oil and petrochemical and refined products;

§	maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary midstream energy assets;

§	enhance the stability of our cash flows by investing in pipelines and other fee-based businesses; and

§	share capital costs and risks through joint ventures or alliances with strategic partners, including those that provide processing, throughput or feedstock volumes for growth capital projects or purchase such projects' end products.

As noted above, part of our business strategy involves expansion through growth capital projects. See Part II, Item 7 of this annual report for information regarding our capital spending program.

Commercial and Liquidity Outlook for 2015

For information regarding our commercial and liquidity outlook for the year ending December 31, 2015, see "General Outlook for 2015" included under Part II, Item 7 of this annual report.

Major Customer Information

Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. Our largest non-affiliated customer for 2014 was Shell Oil Company and its affiliates (collectively, "Shell"), which accounted for 8.5% of our consolidated revenues in 2014. Our largest non-affiliated customer for 2013 and 2012 was BP p.l.c. and its affiliates, which accounted for 9.0% and 9.5%, respectively of our consolidated revenues in these years. For information regarding our revenue recognition policies, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Acquisition of Oiltanking Partners, L.P.

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

Oiltanking owns marine terminals located on the Houston Ship Channel and at the Port of Beaumont with a total of 12 ship and barge docks and approximately 26 MMBbls of crude oil and petroleum products storage capacity. Oiltanking's marine terminal on the Houston Ship Channel is connected by pipeline to our Mont Belvieu, Texas complex and is integral to our growing LPG export, crude oil storage and octane enhancement and propylene businesses. Our Enterprise Crude Houston ("ECHO") facility is also connected to Oiltanking's system. We have had a strategic relationship and enjoyed mutual growth with Oiltanking and its predecessors since 1983. The combination of our legacy midstream assets and Oiltanking's access to waterborne markets and crude oil and

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petroleum products storage assets extends and broadens our midstream energy services business. We believe this combination benefits our producing and consuming customers by enhancing their respective access to supplies, domestic and international markets, and storage.

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

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

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

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

In accordance with the merger agreement and Oiltanking's partnership agreement, the merger was submitted to a vote of Oiltanking's common unitholders, with the required majority of unitholders (including Enterprise's ownership interests representing approximately 65.9% of Oiltanking's outstanding common units) voting to approve the merger on February 13, 2015. Upon approval of the merger, a total of 36,827,557 Enterprise common units were issued to Oiltanking's former public unitholders. After taking into account the aggregate value of consideration issued and paid in the Oiltanking acquisition, our total cost to acquire Oiltanking was approximately $5.9 billion.

In connection with Step 1 of the transaction, we entered into a Liquidity Option Agreement with OTA and Marquard & Bahls ("M&B"), an affiliate of OTA. Pursuant to the Liquidity Option Agreement, we granted M&B the option (the "Liquidity Option") to sell to Enterprise 100% of the issued and outstanding capital stock of OTA (the "Option Securities") at any time within a 90-day period commencing on February 1, 2020. At that time, OTA's only significant asset would be the Enterprise common units it received in Step 1, to the extent that such common units are not sold by M&B prior to the Liquidity Option exercise date. If this put option is exercised, the aggregate consideration to be paid by us for the Option Securities would equal 100% of the then-current fair market value of the OTA-owned Enterprise common units at the closing of the transactions contemplated under the Liquidity Option Agreement. The fair market value would be determined by multiplying the number of Enterprise common units owned by OTA at the time of exercise by the volume-weighted sales price per unit of Enterprise common units as reported by the NYSE (or other national securities exchange, as applicable) for the ten (10) consecutive trading days preceding the exercise. The consideration paid may be in the form of newly issued Enterprise common units, cash or any mix thereof, as determined solely by us. The Liquidity Option Agreement contains indemnification by M&B for certain specified liabilities of OTA following the closing of any exercise of the Liquidity Option, and certain conditions to closing.

If a defined "Trigger Event" occurs, the Liquidity Option may be exercised earlier within a 135-day period following notice of such event. The aggregate consideration to be paid by us for the Option Securities in connection with an exercise of the option due to a Trigger Event will be solely cash, determined in the same manner as the price otherwise payable upon the exercise of the Liquidity Option in the absence of a Trigger Event.

See "Recent Issuance of Unregistered Securities" under Part II, Item 5 for information regarding a registration rights agreement we entered into in connection with the 54,807,352 common units issued as consideration in Step 1 of the Oiltanking acquisition.

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OTA is wholly owned by an affiliate of Oiltanking GmbH, an independent storage provider for crude oil, refined products, liquid chemicals and gases headquartered in Hamburg, Germany. Dr. F. Christian Flach, managing director of Oiltanking GmbH and former chairman of the board of Oiltanking, was named as a director of our general partner in connection with our acquisition of Oiltanking. For additional information regarding Dr. Flach, see Part III, Item 10 of this annual report.

As a result of our acquisition of Oiltanking GP, we began consolidating the financial statements of Oiltanking and its general partner on October 1, 2014. This business combination was accounted for using the acquisition method of accounting. Acquisition accounting requires us to allocate the cost of a business combination to the assets acquired and liabilities assumed based on their estimated fair values on the transaction date. For information regarding our accounting for this business combination, see Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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

Business Segments

The following sections provide an overview of our business segments, including information regarding principal products produced and/or services rendered, properties owned, seasonality and competition. We have five reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

Each of our business segments benefits from the supporting role of our related marketing activities. The main purpose of our marketing activities is to support the utilization of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for the partnership. The financial results of our marketing efforts fluctuate period-to-period due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

For detailed financial information regarding our business segments (including our consolidated revenues by segment), see Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Such financial information is incorporated by reference into this Item 1 and 2 discussion. In addition, we utilize derivative instruments in connection with certain of our operations. For information regarding our use of derivative instruments, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our results of operations and financial condition are subject to certain significant risks. Factors that can affect the demand for our products and services include domestic and international economic conditions, the market price and demand for energy, the cost to develop natural gas and crude oil reserves in the U.S., state and federal regulation, and the cost and availability of capital to energy companies to invest in upstream exploration and production activities. For information regarding such risks, see Part I, Item 1A of this annual report. In addition, our business activities are subject to various federal, state and local laws and regulations governing a wide variety of topics, including commercial, operational, environmental, safety and other matters. For a discussion of the principal effects of such laws and regulations on our business activities, see "Regulatory Matters" within this Part I, Item 1 and 2 discussion.

For management's discussion and analysis of our results of operations, liquidity and capital resources and capital spending program, see Part II, Item 7 of this annual report.

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NGL Pipelines & Services

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

Purity NGL products (ethane, propane, normal butane, isobutane and natural gasoline) are used as feedstocks by the petrochemical industry, as feedstocks by refineries in the production of motor gasoline and as fuel by industrial and residential consumers. Ethane is primarily used in the petrochemical industry as a feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating, engine and industrial fuel. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to produce isobutane through isomerization. Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, and is used in refinery alkylation to enhance the octane content of motor gasoline, in the production of isooctane and other octane additives and in the production of propylene oxide. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline or as a petrochemical feedstock. LPG, which is propane, butane, or a mixture thereof, is used as a feedstock in ethylene plant operations and for power generation and heating purposes.

Natural gas processing plants and related NGL marketing activities. At the core of our natural gas processing business are 24 processing plants located across Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming. In its raw form, natural gas produced at the wellhead (especially in association with crude oil) contains varying amounts of mixed NGLs. Natural gas streams containing NGLs are usually not acceptable for transportation in natural gas pipelines or for commercial use as a fuel and must be sent to natural gas processing plants to remove the NGLs and impurities. Once the natural gas is processed and NGLs and impurities are removed, the natural gas will meet pipeline and commercial quality specifications. On an energy-equivalent basis, most NGLs generally have greater economic value as feedstock for petrochemical and motor gasoline production than as components of a natural gas stream.

Once mixed NGLs are extracted by a natural gas processing plant, they are typically transported to a centralized fractionation facility for separation into purity NGL products. The NGLs we obtain through our processing arrangements (referred to as our "equity NGL production" volumes) or purchase directly from third parties are used in our NGL marketing activities to meet contractual requirements or sold in spot and forward markets. Also, we purchase raw natural gas streams from producers in connection with our natural gas processing activities. Once processed, this natural gas is available for sale through our natural gas marketing activities.

Our commodity-based contracts include keepwhole and margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts and contracts featuring a combination of commodity and fee-based terms. Under keepwhole and margin-band contracts, we take ownership of mixed NGLs extracted from the producer's natural gas stream while replacing the equivalent quantity of energy on a natural gas basis to producers. We recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. Under percent-of-liquids contracts, we take ownership of a portion of the mixed NGLs extracted from the producer's natural gas stream (in lieu of a cash processing fee) and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. Under percent-of-proceeds contracts, we share in the proceeds generated from the sale of mixed NGLs we extract on the producer's behalf (in lieu of a cash

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processing fee). In certain cases, we also utilize contracts that include a combination of commodity-based terms (such as those described above) and fee-based terms. Generally, our natural gas processing agreements have terms ranging from month-to-month to life of the producing lease. Intermediate terms of one to ten years are also common.

The value of natural gas lost as a result of NGL extraction (i.e., shrinkage) and consumed as plant fuel is referred to as plant thermal reduction, which is a significant cost of natural gas processing. To the extent that we are obligated under keepwhole and margin-band contracts to compensate the producer for shrinkage and plant fuel, we are exposed to fluctuations in the price of natural gas; however, margin-band contracts typically contain terms that limit our exposure to such risks. Under the terms of our other processing arrangements (i.e., those agreements with fee-based, percent-of-liquids and percent-of-proceeds terms), the producer typically bears the cost of plant thermal reduction.

If the operating and extraction costs of natural gas processing plants are higher than the incremental value of the NGL products that would be extracted, then recovery levels of certain NGL products, principally ethane, may be purposefully reduced. This scenario is typically referred to as "ethane rejection" and leads to a reduction in NGL volumes available for subsequent transportation, fractionation, storage and marketing. In general, contracts with keepwhole or percent-of-liquids terms provide us the right (but not the obligation) to process natural gas for a producer; thus, we are protected from processing natural gas at an economic loss during times when the sum of our costs exceeds the value of the equity NGL production we would obtain as consideration for processing services.

The following table presents selected information regarding our natural gas processing facilities at February 1, 2015:

			Net Gas	Total Gas
		Our	Processing	Processing
		Ownership	Capacity	Capacity
Description of Asset	Location(s)	Interest	(Bcf/d) (1)	(Bcf/d)
Natural gas processing facilities:
Meeker	Colorado	100.0%	1.80	1.80
Pioneer (two facilities)	Wyoming	100.0%	1.35	1.35
Yoakum	Texas	100.0%	1.05	1.05
Chaco	New Mexico	100.0%	0.60	0.60
North Terrebonne	Louisiana	55.9% (2)	0.53	0.95
Neptune	Louisiana	66.0% (2)	0.43	0.65
Pascagoula	Mississippi	40.0% (2)	0.40	1.50
Sea Robin	Louisiana	50.6% (2)	0.33	0.65
Thompsonville	Texas	100.0%	0.33	0.33
Shoup	Texas	100.0%	0.28	0.28
Gilmore	Texas	100.0%	0.25	0.25
Armstrong	Texas	100.0%	0.25	0.25
Toca	Louisiana	71.9% (2)	0.22	0.30
San Martin	Texas	100.0%	0.20	0.20
Indian Basin	New Mexico	42.4% (2)	0.18	0.18
Delmita	Texas	100.0%	0.15	0.15
Carlsbad	New Mexico	100.0%	0.13	0.13
Sonora	Texas	100.0%	0.12	0.12
Shilling	Texas	100.0%	0.11	0.11
Venice	Louisiana	13.1% (3)	0.10	0.75
Indian Springs	Texas	75.0% (2)	0.09	0.12
Burns Point	Louisiana	50.0% (2)	0.08	0.16
Chaparral	New Mexico	100.0%	0.04	0.04
Total			9.02	11.92

(1) The approximate net gas processing capacity does not necessarily correspond to our ownership interest in each facility. It is based on a variety of factors such as the level of volumes an owner processes at the facility and contractual arrangements with joint owners. (2) We proportionately consolidate our undivided interest in these operating assets. (3) Our ownership in the Venice plant is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C. ("VESCO").

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Our natural gas processing facilities can be characterized as two distinct types: (i) straddle plants situated on mainline natural gas pipelines owned either by us or by third parties or (ii) field plants that process natural gas from gathering pipelines. We operate all of our natural gas processing facilities except for the Pascagoula, Venice and Indian Basin plants. On a weighted-average basis, utilization rates for our natural gas processing plants were 59.1%, 54.1% and 55.9% during the years ended December 31, 2014, 2013 and 2012, respectively.

In March 2013, we completed the third and final phase (or "train") at our Yoakum natural gas processing facility. In the aggregate, the three processing trains at Yoakum can process up to a combined 1.05 Bcf/d of natural gas and extract approximately 144 MBPD of mixed NGLs. The Yoakum facility processes natural gas produced primarily from the Eagle Ford Shale and is linked by pipeline to our Wilson natural gas storage facility and various downstream markets. Mixed NGLs extracted at the Yoakum plant are transported to our NGL fractionation and storage complex at Mont Belvieu, Texas.

In September 2014, we announced plans to construct a new cryogenic natural gas processing plant in Eddy County, New Mexico and associated natural gas and NGL pipeline infrastructure to facilitate growing production of NGL-rich natural gas in the Delaware Basin, a prolific production area in West Texas and southern New Mexico. These assets are expected to begin operations in the first quarter of 2016. The South Eddy natural gas processing plant is expected to have an initial capacity of 200 MMcf/d of natural gas, with the potential for future expansions. Upon completion, this will bring our total natural gas processing plant capacity in the Delaware Basin to approximately 400 MMcf/d.

To supply the new South Eddy plant, we plan to construct approximately 80 miles of natural gas gathering pipelines to complement our existing 1,500 miles of natural gas gathering pipelines located in the Delaware Basin. We also expect to build a 75-mile, 12-inch diameter NGL pipeline to transport NGLs from the South Eddy plant to our Hobbs NGL fractionation and storage facility located in Gaines County, Texas. As a result of multiple pipeline connections at our Hobbs facility, shippers will have access to our NGL fractionation and storage complex at Mont Belvieu, Texas. Additionally, we plan to deliver residue gas from the South Eddy plant through new interconnections with existing third party pipelines located in the vicinity of the plant.

Our NGL marketing activities generate revenues from merchant activities such as term and spot sales of NGLs, which we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and contract purchases. The results of operations from NGL merchant sales are primarily dependent on the difference between NGL sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets. In general, sales prices referenced in the underlying contracts are market-based and may include pricing adjustments for factors such as location, timing or NGL product quality. Market prices for NGLs are subject to fluctuations in response to changes in supply and demand and a variety of additional factors that are beyond our control. Periodically, we attempt to mitigate these price risks through the use of commodity derivative instruments. For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report.

Our NGL export facilities play an integral role in meeting the needs of customers wanting to export NGLs from the U.S. Gulf Coast. Our NGL marketing group assists customers in meeting their export requirements (e.g., through long-term sales contracts with take or pay provisions and/or exchanges of NGLs with export customers) and arranging access to our export facility. We expect export-related sales volumes to increase over the next three years due to existing customer commitments and expanded capacity at our Houston Ship Channel NGL export facility.

Our NGL marketing activities utilize a fleet of approximately 740 railcars, the majority of which are leased from third parties. These railcars are used to deliver feedstocks to our facilities and to distribute NGLs throughout the U.S. and parts of Canada. We have rail loading and unloading capabilities at certain of our terminal facilities in Arizona, California, Kansas, Louisiana, Minnesota, Mississippi, Nevada, New York, North Carolina and Texas. These facilities service both our rail shipments and those of our customers.

NGL pipelines. Our NGL pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities, refineries and import terminals to fractionation plants and storage facilities; gather and distribute purity NGL products to and from fractionation plants, storage and terminal facilities, petrochemical plants, export facilities and refineries; and deliver propane and ethane to destinations along our various pipeline systems.

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The results of operations from our NGL pipelines are primarily dependent upon the volume of NGLs transported and the associated fees we charge for such transportation services. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission ("FERC"), or contractual arrangements. Typically, pipeline transportation revenue is recognized when volumes are transported and delivered. However, under certain NGL pipeline transportation agreements (e.g., those associated with committed shippers on our Texas Express Pipeline, Front Range Pipeline, ATEX and Aegis Ethane Pipeline), customers are required to ship a minimum volume over an agreed-upon period. These arrangements typically entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper "make-up rights"). Revenue attributable to shipper make-up rights is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation.

Excluding inventories owned in connection with our marketing activities, we typically do not take title to the products transported by our NGL pipelines; rather, the shipper retains title and the associated commodity price risk.

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The following table presents selected information regarding our NGL pipelines at February 1, 2015:

		Our
		Ownership	Length
Description of Asset	Location(s)	Interest	(Miles)
NGL pipelines:
Mid-America Pipeline System (1)	Midwest and Western U.S.	100.0%	8,065
South Texas NGL Pipeline System	Texas	100.0%	1,918
Dixie Pipeline (1)	South and Southeastern U.S.	100.0%	1,306
Seminole Pipeline (1)	Texas	100.0%	1,249
ATEX (1)	Texas to Midwest and Northeast U.S.	100.0%	1,205
Chaparral NGL System (1)	Texas, New Mexico	100.0%	1,002
Louisiana Pipeline System	Louisiana	100.0%	953
Texas Express Pipeline (1)	Texas	35.0% (2)	593
Skelly-Belvieu Pipeline (1)	Texas, Oklahoma	50.0% (3)	572
Front Range Pipeline (1)	Colorado, Oklahoma, Texas	33.3% (4)	447
Promix NGL Gathering System	Louisiana	50.0% (5)	351
Rio Grande Pipeline (1)	Texas	70.0% (6)	249
Houston Ship Channel	Texas	100.0%	224
Lou-Tex NGL Pipeline (1)	Texas, Louisiana	100.0%	206
Panola Pipeline	Texas	55.0% (7)	188
Tri-States NGL Pipeline (1)	Alabama, Mississippi, Louisiana	83.3% (8)	167
Chunchula Pipeline (1)	Alabama, Mississippi	100.0%	147
Texas Express Gathering System	Texas, Oklahoma	45.0% (9)	116
Aegis Ethane Pipeline (1)	Texas, Louisiana	100.0%	60
Others (six systems) (9)	Various	Various (11)	311
Total			19,329

(1) Interstate and/or intrastate transportation services provided by these liquids pipelines are regulated by governmental agencies. (2) Our ownership interest in the Texas Express Pipeline is held indirectly through our equity method investment in Texas Express Pipeline LLC. (3) Our ownership interest in the Skelly-Belvieu Pipeline is held indirectly through our equity method investment in Skelly-Belvieu Pipeline Company, L.L.C. (4) Our ownership interest in the Front Range Pipeline is held indirectly through our equity method investment in Front Range Pipeline LLC. (5) Our ownership interest in the Promix NGL Gathering System is held indirectly through our equity method investment in K/D/S Promix, L.L.C. ("Promix"). (6) We own a 70% consolidated interest in the Rio Grande Pipeline through our majority owned subsidiary, Rio Grande Pipeline Company. (7) On January 1, 2015, we formed a joint venture and assigned a 45% interest in Panola Pipeline Company, LLC ("Panola") to third parties. Prior to January 1, 2015, Panola was a wholly owned subsidiary of ours. (8) We own an 83.3% consolidated interest in the Tri-States NGL Pipeline through our majority owned subsidiary, Tri-States NGL Pipeline, L.L.C. (9) Our ownership interest in the Texas Express Gathering System is held indirectly through our equity method investment in Texas Express Gathering LLC ("Texas Express Gathering"). (10) Includes our Belle Rose and Wilprise pipelines located in the coastal regions of Louisiana; two Port Arthur pipelines located in southeast Texas; our San Jacinto pipeline located in East Texas; and a pipeline in Colorado associated with our Meeker facility. Transportation services provided by the Belle Rose and Wilprise pipelines are regulated by governmental agencies. (11) We own a 74.7% consolidated interest in the 30-mile Wilprise pipeline through our majority owned subsidiary, Wilprise Pipeline Company, LLC. We proportionately consolidate our 50% undivided interest in a 45-mile segment of the Port Arthur pipelines. The remainder of these NGL pipelines are wholly owned.

As noted previously, certain of our NGL pipelines are subject to regulation. See "Regulatory Matters" within this Part I, Item 1 and 2 discussion for additional information regarding governmental oversight of liquids pipelines, including tariffs charged for transportation services.

The maximum number of barrels per day that our NGL pipelines can transport depends on the operating balance achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the mix of products being transported). As a result, we measure the utilization rates of our NGL pipelines in terms of net throughput, which is based on our ownership interest. Total net throughput volumes for these pipelines were 2,636 MBPD, 2,540 MBPD and 2,327 MBPD during the years ended December 31, 2014, 2013 and 2012, respectively.

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The following information describes each of our principal NGL pipelines. We operate our NGL pipelines with the exception of the Texas Express Gathering System and Tri-States NGL Pipeline.

The Mid-America Pipeline System is an NGL pipeline system consisting of four primary segments: the 3,147-mile Rocky Mountain pipeline, the 2,136-mile Conway North pipeline, the 624-mile Ethane-Propane Mix pipeline and the 2,158-mile Conway South pipeline. The Mid-America Pipeline System is present in 13 states: Colorado, Illinois, Iowa, Kansas, Minnesota, Missouri, Nebraska, New Mexico, Oklahoma, Texas, Utah, Wisconsin and Wyoming. The Rocky Mountain pipeline transports mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the Hobbs NGL hub located on the Texas-New Mexico border. The Conway North segment links the NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest. NGL hubs such as those at Hobbs and Conway provide buyers and sellers a centralized location for the storage and pricing of products, while also providing connections to intrastate and/or interstate pipelines. The Ethane-Propane Mix segment transports ethane/propane mix primarily to petrochemical plants in Iowa and Illinois from the NGL hub at Conway. The Conway South pipeline connects the Conway hub with Kansas refineries and provides bi-directional transportation of NGLs between the Conway and Hobbs hubs. At the Hobbs NGL hub, the Mid-America Pipeline System interconnects with our Seminole Pipeline and Hobbs NGL fractionation and storage facility. The Mid-America Pipeline System is also connected to 18 non-regulated NGL terminals that we own and operate.

Volumes transported on the Mid-America Pipeline System primarily originate from natural gas processing plants in the Rocky Mountains and Mid-Continent regions, as well as NGL fractionation and storage facilities in Kansas and Texas.

In January 2014, we completed an expansion project involving the Rocky Mountain pipeline of our Mid-America Pipeline System. This expansion project involved looping 265 miles of the Rocky Mountain pipeline, as well as related pump station modifications, which increased transportation capacity on the pipeline from approximately 275 MBPD to 350 MBPD. This expansion project was built to accommodate growing natural gas and NGL production from major supply basins in Colorado, Utah and Wyoming.

The South Texas NGL Pipeline System is a network of NGL gathering and transportation pipelines located in South Texas. This system gathers and transports mixed NGLs from natural gas processing plants in South Texas (owned by us or third parties) to our NGL fractionators in South Texas and Mont Belvieu, Texas. In addition, this system transports purity NGL products from our South Texas NGL fractionators to refineries and petrochemical plants located between Corpus Christi, Texas and Houston, Texas and within the Texas City-Houston area, as well as to interconnects with common carrier NGL pipelines. This includes using parts of our South Texas NGL Pipeline System in connection with our Aegis Ethane Pipeline to extend our planned ethane header system from Mont Belvieu, Texas to Corpus Christi, Texas. The South Texas NGL Pipeline System also connects our South Texas NGL fractionators with our storage facility in Mont Belvieu, Texas.

We placed 188 miles of pipelines belonging to this system into service in phases between May 2012 and March 2013. This included a 168-mile segment that transports mixed NGLs from our Yoakum natural gas processing plant to our Mont Belvieu NGL fractionation and storage complex. In addition, we placed into service a 173-mile NGL pipeline that extends from our Yoakum facility to a third party natural gas processing plant located in LaSalle County, Texas, and provides NGL pipeline takeaway capacity for additional third party gas plants. This pipeline extension commenced operations in June 2013.

The Dixie Pipeline extends from southeast Texas to markets in the southeastern U.S., and transports propane and other NGLs. Propane supplies transported on this system primarily originate from southeast Texas, south Louisiana and Mississippi. This system operates in seven states: Alabama, Georgia, Louisiana, Mississippi, North Carolina, South Carolina and Texas, and is connected to eight non-regulated propane terminals that we own and operate.

§	The Seminole Pipeline transports NGLs from the Hobbs hub and the Permian Basin area of West Texas to markets in southeast Texas including our NGL fractionation facility in Mont Belvieu, Texas. NGLs

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originating on the Mid-America Pipeline System are the primary source of throughput for the Seminole Pipeline.

The ATEX, or Appalachia-to-Texas Express, pipeline primarily transports ethane in southbound service from four NGL fractionation plants located in Ohio, Pennsylvania and West Virginia to our Mont Belvieu storage complex. The ethane extracted by these fractionation facilities originates from the Marcellus and Utica Shale production areas. ATEX began commercial operations in January 2014 and operates in nine states: Arkansas, Illinois, Indiana, Louisiana, Missouri, Ohio, Pennsylvania, Texas and West Virginia. In addition to newly constructed pipeline segments, significant portions of ATEX consist of pipeline segments that were formerly used in refined products transportation service by our TE Products Pipeline. Initial throughput capacity for ATEX is 125 MBPD, which could be expanded to approximately 265 MBPD with certain system modifications.

ATEX terminates at our Mont Belvieu storage complex, which includes approximately 111 MMBbls of NGL and petroleum liquid storage capacity and an extensive pipeline distribution system. With the addition of our Aegis Ethane Pipeline, we will link Marcellus and Utica Shale-produced ethane to existing ethylene production facilities along the U.S. Gulf Coast and provide supply security to support construction of new third party ethylene plants currently planned at Texas and Louisiana petrochemical facilities. Also, since our Houston region pipeline network supports our export terminals on the Houston Ship Channel, ethane volumes delivered to Mont Belvieu via ATEX may contribute to future exports of U.S.-produced ethane to international markets.

The Chaparral NGL System transports mixed NGLs from natural gas processing plants in West Texas and New Mexico to Mont Belvieu, Texas. This system consists of the 822-mile Chaparral pipeline and the 180-mile Quanah pipeline. Interstate and intrastate transportation services provided by the Chaparral pipeline are regulated; however, transportation services provided by the Quanah pipeline are not.

The Louisiana Pipeline System is a network of NGL pipelines located in southern Louisiana. This system transports NGLs originating in Louisiana and Texas to refineries and petrochemical plants located along the Mississippi River corridor in southern Louisiana. This system also provides transportation services for our natural gas processing plants, NGL fractionators and other assets located in Louisiana. Originating from a central point in Henry, Louisiana, pipelines extend westward to Lake Charles, Louisiana, northward to an interconnect with the Dixie Pipeline at Breaux Bridge, Louisiana and eastward in Louisiana, where our Promix, Norco and Tebone NGL fractionation and related storage facilities are located.

The Texas Express Pipeline extends from Skellytown, Texas to our NGL fractionation and storage complex at Mont Belvieu, Texas. This pipeline commenced operations in November 2013. Mixed NGLs from the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown. The Texas Express Pipeline also transports mixed NGLs from two gathering systems owned by Texas Express Gathering to Mont Belvieu. In addition, mixed NGLs from the Denver-Julesburg supply basin are transported to the Texas Express Pipeline using the Front Range Pipeline, which commenced operations in February 2014. Throughput capacity for the Texas Express Pipeline is 280 MBPD, which could be expanded to approximately 400 MBPD with certain system modifications.

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

The Front Range Pipeline, which commenced operations in February 2014, transports mixed NGLs from natural gas processing plants located in the Denver-Julesburg Basin in Colorado to an interconnect with our Texas Express Pipeline and Mid-America Pipeline System at Skellytown, Texas. Throughput capacity for the Front Range Pipeline is 150 MBPD, which could be expanded to approximately 230 MBPD with certain system modifications.

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§	The Promix NGL Gathering System gathers mixed NGLs from natural gas processing plants in southern Louisiana for delivery to our Promix NGL fractionator.

§	The Rio Grande Pipeline transports mixed NGLs from near Odessa, Texas to a pipeline interconnect at the Mexican border south of El Paso, Texas.

§	The Houston Ship Channel pipeline system connects our Mont Belvieu complex to our Houston Ship Channel import/export terminals and various third party petrochemical plants, refineries and other pipelines located along the Houston Ship Channel.

The Panola Pipeline transports mixed NGLs from points near Carthage, Texas to Mont Belvieu 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.

§	The Lou-Tex NGL Pipeline system transports mixed NGLs, purity NGL products and refinery grade propylene between the Louisiana and Texas markets.

§	The Tri-States NGL Pipeline transports mixed NGLs from Mobile Bay, Alabama to points near Kenner, Louisiana and is operated by BP.

§	The Chunchula Pipeline transports propane and butane from the Alabama-Florida border to our storage facility at Petal, Mississippi.

The Texas Express Gathering System is comprised of two NGL gathering systems that deliver volumes to the Texas Express Pipeline. These gathering systems commenced operations in November 2013. The Elk City gathering system is currently comprised of 55 miles of pipeline and gathers mixed NGLs from natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma. The North Texas gathering system currently comprises 61 miles of pipeline and gathers mixed NGLs from natural gas processing plants in the Barnett Shale production area in North Texas. Enbridge serves as operator of these two NGL gathering systems.

The Aegis Ethane Pipeline (or "Aegis") represents a key component of our planned ethane header system stretching from Corpus Christi, Texas to the Mississippi River in Louisiana. In September 2014, we completed the first segment, or 60 miles, of the planned 270-mile Aegis pipeline. As a result of this completion, we commenced ethane deliveries between our Mont Belvieu storage complex and customers in Beaumont, Texas. After taking into account existing South Texas midstream infrastructure and completion of the first segment of Aegis, our ethane header system is now in service from Corpus Christi to Beaumont. The remainder of Aegis will be completed in two phases: the next segment between Beaumont and Lake Charles, Louisiana is expected to be completed in the third quarter of 2015 and the final segment from Lake Charles to the Mississippi River is expected to be completed by the end of 2015. Aegis is expected to have a throughput capacity of up to 425 MBPD.

NGL and related product storage facilities. We use both underground storage caverns (or wells) and above ground storage tanks to store mixed NGLs and purity NGL, petrochemical and related products owned by us and our customers. We collect storage revenues under our NGL and related product storage contracts based on the number of days a customer has volumes in storage multiplied by a storage fee (as defined in each contract). With respect to capacity reservation agreements, we collect a fee for reserving storage capacity for certain customers in our underground storage wells. Customers pay reservation fees based on the level of storage capacity reserved rather than the actual volumes stored. When a customer exceeds its reserved capacity, we charge that customer excess storage fees. In addition, we generally charge customers throughput fees based on volumes delivered into and subsequently withdrawn from storage. Accordingly, the results of operations from these assets are dependent upon the level of storage capacity reserved by customers, the volume of product delivered into and withdrawn from storage and the level of fees charged.

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The following table presents selected information regarding our NGL and related product storage assets at February 1, 2015:

	Net Usable
	Storage
	Capacity
Storage Capacity by State	(MMBbls)
Texas	125.9
Louisiana	14.0
Kansas	8.6
Mississippi	5.1
Others (1)	7.2
Total (2)	160.8

(1) Includes storage capacity at facilities in Alabama, Arizona, California, Georgia, Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Nevada, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina and Wisconsin. (2) Our aggregate net usable storage capacity includes 17.8 MMBbls held under long-term operating leases at facilities located in Indiana, Kansas, Louisiana and Texas. Approximately 1.5 MMBbls of our net usable storage capacity in Louisiana is held indirectly through our equity method investment in Promix. The remainder of our NGL underground storage caverns and above ground storage tanks are wholly owned.

Our NGL and related product storage facilities are important components of our midstream energy infrastructure. We operate these facilities, with the exception of certain Louisiana storage locations, the leased Markham facility in Texas and another leased facility in Kansas. Our largest underground storage facility is located in Mont Belvieu, Texas. This facility consists of 35 underground storage caverns used to store and redeliver mixed NGLs and NGL purity, petrochemical and related products for industrial customers located along the upper Texas Gulf Coast. This facility has an aggregate usable storage capacity of approximately 111 MMBbls, a brine system with approximately 20 MMBbls of above-ground brine storage pit capacity and four wells available for brine production.

Houston Ship Channel NGL export dock and related operations. We own a marine terminal located on the Houston Ship Channel having the capability to load cargoes of fully refrigerated, low-ethane propane and/or butane (collectively referred to as LPG) onto multiple tanker vessels simultaneously. Currently, the terminal has a loading capability of up to 7.5 MMBbls per month of LPG. Our LPG export services continue to benefit from increased NGL supplies produced from domestic shale plays such as the Eagle Ford Shale and international demand for propane as a feedstock in ethylene plant operations and for power generation and heating purposes. Our average LPG loading volumes at this export terminal were 248 MBPD, 231 MBPD and 131 MBPD during the years ended December 31, 2014, 2013 and 2012, respectively.

In September 2013, we announced an expansion project at this export terminal that is expected to increase its ability to load cargoes from 7.5 MMBbls per month to approximately 9.0 MMBbls per month. This expansion project is expected to be completed in the first quarter of 2015. In January 2014, we announced a further expansion of this export terminal that is expected to increase its 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 the expansion projects, which are supported by long-term LPG export agreements, are completed.

We also own an NGL import facility located at the same terminal as our Houston Ship Channel LPG export terminal. This import facility can offload NGLs from tanker vessels at rates up to 14,000 barrels per hour depending on the product. Our NGL import volumes were minimal during each of the years ended December 31, 2014, 2013 and 2012.

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Historically, we leased the site that our Houston Ship Channel NGL import and LPG export facility is located on from Oiltanking. Due to completion of the Oiltanking Merger in February 2015, we now own these facilities.

The results of operations from our export and import terminals are primarily dependent upon the volume handled and the associated fees we charge for such services. Revenue from NGL import and LPG export terminaling activities is recorded in the period services are provided. Customers, which include our NGL marketing business, are typically billed a fee per unit of volume loaded or unloaded.

Houston Ship Channel ethane export dock. In April 2014, we announced plans to construct a fully refrigerated ethane export facility on the Houston Ship Channel. The new facility, which is located near La Porte, Texas, is expected to have an aggregate loading rate of approximately 10,000 barrels per hour and is supported by long-term contracts. The ethane export facility will be integrated with our Mont Belvieu NGL fractionation and storage complex. We believe that our integrated NGL system offers supply assurance and diversification for the ethane export facility. We expect the ethane export facility to begin operations in the third quarter of 2016.

Our ethane export facility will provide new markets for domestically-produced ethane, and will assist U.S. producers in increasing their associated production of natural gas and crude oil. We estimate that U.S. ethane production capacity currently exceeds U.S. demand by 400 to 500 MBPD and could exceed demand by up to 700 MBPD by 2020, after considering the estimated incremental demand from new ethylene facilities that have been announced.

NGL fractionation. We own or have interests in 15 NGL fractionators, which separate mixed NGL streams into purity NGL products, located in Texas and Louisiana. The primary sources of mixed NGLs fractionated in the U.S. are domestic natural gas processing plants, crude oil refineries and imports of butane and propane mixtures. Mixed NGLs sourced from domestic natural gas processing plants and crude oil refineries are typically transported to NGL fractionation facilities by NGL pipelines and, to a lesser extent, by railcar and truck.

Mixed NGLs extracted by domestic natural gas processing plants (e.g., by our Yoakum plant) represent the largest source of volumes processed by our NGL fractionators. Based upon industry data, we believe that sufficient volumes of mixed NGLs, especially those originating from natural gas processing plants located along the Gulf Coast and in the Rocky Mountains and Mid-Continent regions, will be available for fractionation in commercially viable quantities for the foreseeable future. Significant volumes of mixed NGLs are contractually committed to be processed at our NGL fractionators by joint owners and third party customers.

Our NGL fractionation facilities process mixed NGL streams for third party customers and also support our NGL marketing activities. We typically earn revenues from NGL fractionation under fee-based arrangements. These fees (usually stated in cents per gallon) are contractually subject to adjustment for changes in certain fractionation expenses (e.g., natural gas fuel costs). At our Norco facility in Louisiana, we perform fractionation services for certain customers under percent-of-liquids contracts.

The results of operations of our NGL fractionation business are generally dependent upon the volume of mixed NGLs fractionated and either the level of fractionation fees charged (under fee-based contracts) or the value of NGLs received (under percent-of-liquids arrangements). Our fee-based fractionation customers retain title to the NGLs that we process for them. To the extent we fractionate volumes for customers under percent-of-liquids contracts, we are exposed to fluctuations in NGL prices (i.e., commodity price risk). We attempt to mitigate these risks through the use of commodity derivative instruments such as forward sales contracts.

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The following table presents selected information regarding our NGL fractionation facilities at February 1, 2015:

		Our	Net Plant	Total Plant
		Ownership	Capacity	Capacity
Description of Asset	Location	Interest	(MBPD) (1)	(MBPD)
NGL fractionation facilities:
Mont Belvieu	Texas	Various (2)	572	670
Shoup and Armstrong	Texas	100.0%	98	98
Hobbs	Texas	100.0%	75	75
Norco	Louisiana	100.0%	75	75
Promix	Louisiana	50.0% (3)	73	145
BRF	Louisiana	32.2% (4)	19	60
Tebone	Louisiana	55.9% (5)	17	30
Total			929	1,153

(1) The approximate net plant capacity does not necessarily correspond to our ownership interest in each facility. It is based on a variety of factors such as the level of volumes an owner processes at the facility and contractual arrangements with joint owners. (2) Six of our eight Mont Belvieu NGL fractionators are held jointly with third parties. We proportionately consolidate a 75% undivided interest in three units and substantially all of a fourth unit. We own a 75% consolidated equity interest in NGL fractionators seven and eight through our majority owned subsidiary, Enterprise EF78 LLC. The remaining two units, NGL fractionators five and six are wholly owned by us. (3) Our ownership interest in the Promix fractionator is held indirectly through our equity method investment in Promix. (4) Our ownership interest in the BRF fractionator is held indirectly through our equity method investment in Baton Rouge Fractionators LLC ("BRF"). (5) We proportionately consolidate our undivided 55.9% interest in the Tebone fractionator.

On a weighted-average basis, overall utilization rates for our NGL fractionators were 89.4%, 88.5% and 91.9% during the years ended December 31, 2014, 2013 and 2012, respectively. We operate all of our NGL fractionators.

The following information describes each of our principal NGL fractionators:

Our Mont Belvieu NGL fractionation complex is located at Mont Belvieu, Texas, which is a key hub of the global NGL industry. Our Mont Belvieu NGL fractionation assets process mixed NGLs from several major NGL supply basins in North America, including the Eagle Ford Shale, Rocky Mountains, Mid-Continent, Permian Basin and San Juan Basin. Our Mont Belvieu NGL fractionation complex features connectivity to our network of NGL supply and distribution pipelines, approximately 111 MMBbls of salt dome storage capacity, and access to international markets through our existing LPG export facility and future ethane export facility.

We placed the seventh and eighth NGL fractionators at our Mont Belvieu complex into operation in September 2013 and November 2013, respectively. These two new fractionators (each with 85 MBPD of fractionation capacity) were built to handle NGL production from domestic shale plays, including the Eagle Ford Shale in South Texas and other supply basins in the Rocky Mountains and Mid-Continent regions.

In September 2014, we announced plans to build a ninth NGL fractionator adjacent to our complex in Mont Belvieu, Texas. If constructed, the ninth fractionator is expected to have a capacity of 85 MBPD. We have secured the required permits and emission credits for the ninth and a possible, similarly-sized tenth NGL fractionator at Mont Belvieu. We are evaluating the timing of these projects in light of current business conditions.

Our Shoup and Armstrong fractionators process mixed NGLs supplied by our South Texas natural gas processing plants. Purity NGL products from the Shoup and Armstrong fractionators are transported to local markets in the Corpus Christi area and also to Mont Belvieu, Texas using our South Texas NGL Pipeline System.

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Our Hobbs NGL fractionator serves NGL producers in West Texas, New Mexico, California and northern Mexico. The Hobbs fractionator receives mixed NGLs from several major supply basins, including the Mid-Continent, Permian Basin, San Juan Basin and Rocky Mountains. The facility is located at the interconnect of our Mid-America Pipeline System and Seminole Pipeline, thus providing us the operating flexibility to supply both the nation's largest NGL hub at Mont Belvieu as well as access to the second-largest NGL hub at Conway, Kansas.

§	Our Norco NGL fractionator receives mixed NGLs via pipeline from refineries and natural gas processing plants located in southern Louisiana and along the Mississippi and Alabama Gulf Coast, including our Pascagoula, Venice and Toca facilities.

The Promix NGL fractionator receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast, including our Neptune and Pascagoula facilities. In addition to the Promix NGL Gathering System, Promix owns three NGL storage caverns and leases a fourth NGL storage cavern. Promix also owns a barge loading facility.

§	The BRF fractionator receives mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana.

Seasonality. Our natural gas processing and NGL fractionation operations typically exhibit little seasonal variation. Our NGL marketing activities utilize inventories of purity NGL products. Propane and normal butane inventories are typically at higher levels from March through November since these products are normally in higher demand and at higher price levels during the winter months. Ethane, isobutane and natural gasoline inventories are generally stable and less cyclical throughout the year.

NGL pipeline transportation volumes are generally higher from October through March due to higher demand for propane (for residential heating purposes) and normal butane (for blending into motor gasoline). With respect to our NGL and related product storage facilities, we usually experience an increase in demand for storage services during the spring and summer months due to increased feedstock storage requirements for motor gasoline production and a decrease during the fall and winter months when propane inventories are being drawn down for heating needs. Likewise, the revenues we recognize from NGL marketing activities are predicated on the overall demand for such products, which may fluctuate due to seasonal needs for gasoline blending feedstocks, heating requirements and similar factors.

Seasonality has little impact on our LPG export terminal operations; however, historical NGL import volumes have been higher during the spring and summer months. Lastly, our facilities located along the Gulf Coast of the U.S. may be affected by weather events such as hurricanes and tropical storms, which generally arise during the summer and fall months.

Competition. Within their respective market areas, our natural gas processing business activities and related NGL marketing activities encounter competition primarily from fully integrated oil companies, intrastate pipeline companies, major interstate pipeline companies and their non-rate regulated affiliates, financial institutions with trading platforms and independent processors. Each of our marketing competitors has varying levels of financial and personnel resources, and competition generally revolves around price, quality of customer service and proximity to customers and other market hubs. In the markets served by our NGL pipelines, we compete with a number of intrastate and interstate pipeline companies (including those affiliated with major oil, petrochemical and natural gas companies) and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service.

Our primary competitors in the NGL and related product storage businesses are integrated major oil companies, chemical companies and other storage and pipeline companies. We compete with other storage service providers primarily in terms of the fees charged, number of pipeline connections provided and operational dependability. Our import and export operations compete with those operated by major oil and chemical companies primarily in terms of loading and offloading throughput capacity.

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We compete with a number of NGL fractionators in Texas, Louisiana, New Mexico and Kansas. Competition for such services is primarily based on the fractionation fee charged. However, the ability of an NGL fractionator to receive a customer's mixed NGLs and store and distribute the resulting purity NGL products is also an important competitive factor and is a function of having the necessary pipeline and storage infrastructure.

Onshore Natural Gas Pipelines & Services

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

Onshore natural gas pipelines. Our onshore natural gas pipeline systems gather and transport natural gas from major producing regions such as the Eagle Ford Shale, Haynesville Shale, San Juan, Barnett Shale, Permian, Piceance and Greater Green River supply basins. In addition, certain of these pipeline systems receive natural gas production from Gulf of Mexico developments through coastal pipeline interconnects with offshore pipelines. Our onshore natural gas pipelines receive natural gas from producers, other pipelines or shippers at the wellhead or through system interconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial or municipal customers, storage facilities or other onshore pipelines.

The results of operations from our onshore natural gas pipelines and related storage assets are primarily dependent upon the volume of natural gas transported or stored, the level of firm capacity reservations made by shippers, and the associated fees we charge for such activities. Transportation fees charged to shippers (typically per MMBtu of natural gas) are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. Certain of our onshore natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved (whether or not the shipper actually utilizes such capacity). Under our natural gas storage revenue contracts, there are typically two components: (i) monthly demand payments, which are associated with a customer's storage capacity reservation and paid regardless of actual usage, and (ii) storage fees per unit of volume stored at our facilities.

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The following table presents selected information regarding our onshore natural gas pipelines and related storage assets at February 1, 2015:

				Approximate Net Capacity
		Our			Usable
		Ownership	Length	Pipelines	Storage
Description of Asset	Location(s)	Interest	(Miles)	(MMcf/d)	(Bcf)
Onshore natural gas pipelines and related storage assets:
Texas Intrastate System (1)	Texas	Various (2)	8,173	6,640	12.9
Acadian Gas System (1)	Louisiana	100.0% (3)	1,324	3,100	1.3
Jonah Gathering System	Wyoming	100.0%	786	2,360	--
San Juan Gathering System	New Mexico, Colorado	100.0%	6,126	1,750	--
Piceance Basin Gathering System	Colorado	100.0%	189	1,600	--
White River Hub (4)	Colorado	50.0% (5)	10	1,500	--
Haynesville Gathering System	Louisiana, Texas	100.0%	358	1,300	--
Fairplay Gathering System	Texas	100.0% (6)	275	285	--
Carlsbad Gathering System	Texas, New Mexico	100.0%	920	220	--
Indian Springs Gathering System (7)	Texas	80.0% (8)	174	160	--
Delmita Gathering System	Texas	100.0%	199	145	--
South Texas Gathering System	Texas	100.0%	510	143	--
Big Thicket Gathering System (7)	Texas	100.0%	256	60	--
Total			19,300		14.2

(1) Transportation services provided by these systems are regulated by governmental agencies. (2) Of the 8,173 miles comprising the Texas Intrastate System, we lease 240 miles from a third party. We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,459 miles of pipeline. Our Wilson natural gas storage facility consists of five underground salt dome natural gas storage caverns with 12.9 Bcf of usable storage capacity, four of which (comprising 6.9 Bcf of usable capacity) are held under an operating lease that expires in January 2028. The remainder of our Texas Intrastate System is wholly owned. (3) The Acadian Gas System is wholly owned except for an underground salt dome natural gas storage facility that we hold under an operating lease that expires in December 2018. (4) Interstate transportation service provided by this facility is regulated by governmental agencies. (5) Our ownership interest in the White River Hub facility is held indirectly through our equity method investment in White River Hub, LLC ("White River Hub"). (6) The Fairplay Gathering System includes approximately 52 miles of pipeline held under an operating lease. (7) Intrastate transportation services provided by the Indian Springs Gathering System and Big Thicket Gathering System are regulated by governmental agencies. (8) We proportionately consolidate our 80% undivided interest in the Indian Springs Gathering System.

As noted previously, certain of our natural gas pipelines are subject to regulation. See "Regulatory Matters" within this Part I, Item 1 and 2 discussion for additional information regarding governmental oversight of natural gas pipelines, including tariffs charged for transportation services.

On a weighted-average basis, overall utilization rates for our onshore natural gas pipelines were approximately 60.5%, 65.2% and 67.7% during the years ended December 31, 2014, 2013 and 2012, respectively. These utilization rates represent actual natural gas volumes delivered as a percentage of our nominal delivery capacity and do not reflect firm capacity reservation agreements where throughput capacity is reserved whether or not the shipper actually utilizes such capacity.

The following information describes each of our principal onshore natural gas pipelines. With the exception of the White River Hub and certain segments of the Texas Intrastate System, we operate our onshore natural gas pipelines and storage facilities.

The Texas Intrastate System is comprised of the 6,833-mile Enterprise Texas pipeline system, the 629-mile Channel pipeline system, the 584-mile Waha gathering system and the 127-mile TPC Offshore gathering system. The Wilson natural gas storage facility, which is an important part of the Texas Intrastate System, is comprised of a network of underground salt dome storage caverns located in Wharton County, Texas.

The Texas Intrastate System gathers, transports and stores natural gas from supply basins in Texas such as the Eagle Ford Shale and Barnett Shale for redelivery to local gas distribution companies and electric generation and industrial and municipal consumers as well as to connections with intrastate and interstate

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pipelines. The Texas Intrastate System serves commercial markets in Texas, including Corpus Christi, the San Antonio/Austin area, the Beaumont/Orange area and the Houston area, including the Houston Ship Channel industrial market.

The Acadian Gas System transports, stores and markets natural gas in Louisiana. The Acadian Gas System is comprised of the 584-mile Cypress pipeline, 444-mile Acadian pipeline, 270-mile Haynesville Extension pipeline and 26-mile Enterprise Pelican pipeline. The Acadian Gas System includes a leased underground salt dome natural gas storage cavern located at Napoleonville, Louisiana. The Acadian Gas System links natural gas supplies from Louisiana (e.g., from Haynesville Shale supply basin) and offshore Gulf of Mexico developments with local gas distribution companies, electric generation plants and industrial customers located primarily in the Baton Rouge/New Orleans/Mississippi River corridor.

The Jonah Gathering System is located in the Greater Green River Basin of southwest Wyoming. This system gathers natural gas from the Jonah and Pinedale supply fields for delivery to regional natural gas processing plants, including our Pioneer facilities, for ultimate delivery into major interstate pipelines.

The San Juan Gathering System serves producers in the San Juan Basin of northern New Mexico and southern Colorado. This system gathers natural gas from production wells located in the San Juan Basin and delivers the natural gas either directly into major interstate pipelines or to regional processing and treating plants, including our Chaco processing facility and Val Verde treating plant located in New Mexico, for ultimate delivery into major interstate pipelines.

The Piceance Basin Gathering System consists of a network of gathering pipelines located in the Piceance Basin of northwestern Colorado. The Piceance Basin Gathering System gathers natural gas throughout the Piceance Basin to our Meeker natural gas processing complex for ultimate delivery into the White River Hub and other major interstate pipelines.

§	The White River Hub is a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado. The facility enables producers to access six interstate natural gas pipelines and has a gross throughput capacity of 3 Bcf/d of natural gas.

The Haynesville Gathering System consists of the 215-mile State Line gathering system, the 73-mile Southeast Mansfield gathering system and the 70-mile Southeast Stanley gathering system. The Haynesville Gathering System gathers natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas for delivery to regional markets, including (through an interconnect with the Haynesville Extension pipeline) markets served by our Acadian Gas System.

§	The Fairplay Gathering System gathers natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations within Panola and Rusk Counties in East Texas for delivery to regional markets.

§	The Carlsbad Gathering System gathers natural gas from the Permian Basin region of Texas and New Mexico for delivery to natural gas processing plants, including our Chaparral, Carlsbad and Indian Basin plants, as well as delivery into the El Paso Natural Gas and Transwestern pipelines.

In addition to our natural gas pipelines, we own a natural gas treating facility (the "Central Treating Facility") located in Rio Blanco County, Colorado. This facility can treat up to 200 MMcf/d of natural gas and serves Exxon Mobil Corporation's ("ExxonMobil") producing properties in the Piceance Basin. Natural gas delivered to the Central Treating Facility by ExxonMobil is treated to remove impurities and transported to our Meeker gas plant for further processing.

Natural gas marketing activities. Our natural gas marketing activities generate revenues from the sale and delivery to local gas distribution companies and other customers of natural gas purchased from producers, regional natural gas processing plants and the open market. The results of operations from our natural gas marketing activities are primarily dependent upon the difference, or spread, between natural gas sales prices and the associated

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purchase price and other costs, including those costs attributable to the use of our other assets. In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location.

We are exposed to commodity price risk to the extent that we take title to natural gas volumes in connection with our natural gas marketing activities and certain intrastate natural gas transportation contracts. In addition, we purchase and resell natural gas for certain producers that use our San Juan, Carlsbad and Jonah Gathering Systems and certain segments of our Acadian Gas and Texas Intrastate Systems. Also, several of our natural gas gathering systems, while not providing marketing services, have some exposure to risks related to fluctuations in commodity prices through transportation arrangements with shippers. For example, nearly all of the transportation revenues generated by our San Juan Gathering System are based on a percentage of a regional natural gas price index. This index may fluctuate based on a variety of factors, including changes in natural gas supply and consumer demand. We use derivative instruments to mitigate our exposure to commodity price risks associated with our natural gas pipelines and services business.

Seasonality. Our onshore natural gas pipelines typically experience higher throughput rates during the summer months as utility companies that use natural gas for power generation increase their electricity output to meet residential and commercial demand for air conditioning. Higher throughput rates are also experienced in the winter months as natural gas is used to meet residential and commercial heating requirements. In addition, our facilities located along the U.S. Gulf Coast may be affected by weather events such as hurricanes and tropical storms, which generally arise during the summer and fall months.

Competition. Within their market areas, our onshore natural gas pipelines compete with other natural gas pipelines on the basis of price (in terms of transportation fees), quality of customer service and operational flexibility. Our natural gas marketing activities compete primarily with other natural gas pipeline companies and their marketing affiliates as well as standalone natural gas marketing and trading firms. Competition in the natural gas marketing business is based primarily on competitive pricing, proximity to customers and market hubs, and quality of customer service.

Onshore Crude Oil Pipelines & Services

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

Onshore crude oil pipelines. Our onshore crude oil pipeline systems gather and transport crude oil in New Mexico, Oklahoma and Texas to refineries, centralized storage terminals and connecting pipelines.

The results of operations from crude oil transportation services are primarily dependent upon the volume of crude oil transported and the level of fees charged to shippers (typically per barrel of crude oil). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. Typically, revenue associated with these arrangements is recognized when volumes have been transported and delivered; however, under certain of our crude oil pipeline transportation agreements (e.g., certain shippers on Seaway), customers are required to ship a minimum volume over an agreed-upon period, with make-up rights. Revenue attributable to shipper make-up rights is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation.

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The following table presents selected information regarding our onshore crude oil pipelines at February 1, 2015:


		Our	Pipeline
		Ownership	Length
Description of Asset	Location(s)	Interest	(Miles)
Crude oil pipelines:
Seaway Pipeline (1)	Texas, Oklahoma	50.0% (2)	1,300
Red River System (1)	Texas, Oklahoma	100.0%	1,602
West Texas System (1)	Texas, New Mexico	100.0%	899
South Texas Crude Oil Pipeline System (1)	Texas	100.0%	860
Basin Pipeline (1)	Texas, New Mexico, Oklahoma	13.0% (3)	519
Eagle Ford Crude Oil Pipeline System	Texas	50.0% (4)	175
Total			5,355

(1) Transportation services provided by these liquids pipelines are regulated by governmental agencies. (2) Our ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Pipeline Company LLC ("Seaway"). (3) We proportionately consolidate our undivided interest in the Basin Pipeline. (4) Our ownership interest in the Eagle Ford Crude Oil Pipeline System is held indirectly through our equity method investment in Eagle Ford Pipeline LLC.

The maximum number of barrels per day that our onshore crude oil pipelines can transport depends on the operating balance achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and grades of crude oil being transported). As a result, we measure the utilization rates of our crude oil pipelines in terms of net throughput, which is based on our ownership interest. Total net throughput volumes for these pipelines were 1,278 MBPD, 1,175 MBPD and 828 MBPD during the years ended December 31, 2014, 2013 and 2012, respectively.

As noted previously, certain of our crude oil pipelines are subject to regulation. See "Regulatory Matters" within this Part I, Item 1 and 2 discussion for additional information.

The following information describes each of our principal onshore crude oil pipelines, all of which we operate with the exception of the Basin Pipeline and Eagle Ford Crude Oil Pipeline System.

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

The Longhaul System consists of two 500-mile, 30-inch diameter pipelines that provide north-to-south transportation of crude oil from the Cushing hub to Seaway's Jones Creek terminal located near Freeport, Texas and our terminal located near Katy, Texas. We completed the second of these two pipelines (referred to as the "Seaway Loop") in July 2014. With the looping project complete, the aggregate transportation capacity of the Longhaul System is approximately 850 MBPD, depending on the type and mix of crude oil being transported and other variables. Crude oil deliveries using the Seaway Loop commenced in December 2014.

The Freeport System consists of a marine dock, three pipelines and other related facilities that transport crude oil to and from Freeport, Texas to the Jones Creek terminal. The Texas City System consists of a marine dock, storage tanks, various pipelines and other related facilities that deliver crude oil from Texas City, Texas to Galena Park, Texas and other nearby locations. The Freeport System and Texas City System provide intrastate transportation service. The intrastate transportation capacity of the Freeport System and Texas City System is approximately 220 MBPD and 800 MBPD, respectively.

In total, the Seaway Pipeline includes 7.9 MMBbls of crude oil storage tank capacity (3.9 MMBbls net to our ownership interest). This includes two storage tanks at the Jones Creek terminal that are connected to

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the Longhaul System and two storage tanks owned by Seaway that are located at our Enterprise Crude Houston ("ECHO") terminal.

In January 2013, Seaway made certain pump station additions and modifications at its Cushing origin. In January 2014, Seaway placed into service a 65-mile, 36-inch diameter pipeline from its Jones Creek terminal to our ECHO terminal. In August 2014, Seaway completed construction of an additional 100-mile, 30-inch diameter pipeline between ECHO and refinery customers in the Beaumont/Port Arthur, Texas area. In January 2015, Seaway placed into service the aforementioned two storage tanks at our ECHO terminal.

The interstate tariffs charged by Seaway to its committed and uncommitted shippers are the subject of an ongoing rate proceeding at the FERC. For information regarding this proceeding, see "Regulatory Matters – FERC Regulation – Liquids Pipelines," within this Part I, Item 1 and 2 discussion.

§	The Red River System transports crude oil from North Texas and southern Oklahoma for delivery to local refineries and pipeline interconnects for further transportation to the Cushing hub. The Red River System is connected to 1.2 MMBbls of crude oil storage capacity that we own and operate.

§	The West Texas System connects crude oil gathering systems in West Texas and southeast New Mexico to our terminal facility in Midland, Texas. The West Texas System is connected to 0.5 MMBbls of crude oil storage capacity that we own and operate.

§	The South Texas Crude Oil Pipeline System transports crude oil originating in South Texas, including growing production from the Eagle Ford Shale supply basin, to refineries in the Greater Houston area.

The South Texas Crude Oil Pipeline System includes our Eagle Ford Expansion pipeline, which has a crude oil transportation capacity of 350 MBPD. The Eagle Ford Expansion pipeline originates at our Lyssy station in Wilson County, Texas and extends 147 miles to Sealy, Texas. It includes 2.4 MMBbls of crude oil storage consisting of 0.2 MMBbls in Karnes County, Texas, 0.6 MMBbls in Wilson County, Texas, 0.4 MMBbls in Gonzales County, Texas and 1.2 MMBbls at Sealy. Crude oil supplies arriving at Sealy on the Eagle Ford Expansion pipeline are delivered to refiners in the Greater Houston area using affiliate and third party owned pipelines. In addition, shippers have access to our ECHO crude oil storage terminal.

Including the storage capacity associated with the Eagle Ford Expansion pipeline, the South Texas Crude Oil Pipeline System includes a total of 3.4 MMBbls of crude oil storage capacity that we own and operate.

The South Texas Crude Oil Pipeline System includes our Rancho I and II pipelines. The Rancho I pipeline extends 63 miles from Sealy, Texas to our ECHO terminal. We are currently constructing a loop pipeline (the "Rancho II" pipeline) that will consist of 88-miles of 36-inch diameter pipe extending from Sealy to ECHO. We expect the Rancho II pipeline to be completed in July 2015.

§	The Basin Pipeline transports crude oil from the Permian Basin in West Texas and southern New Mexico to the Cushing hub. The Basin Pipeline includes 5 MMBbls of crude oil storage capacity (0.8 MMBbls net to our ownership interest).

The Eagle Ford Crude Oil Pipeline System transports crude oil and condensate for producers in South Texas. This system consists of a 140-mile crude oil and condensate pipeline extending from Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and continuing on to Corpus Christi, Texas. The system also includes a 35-mile pipeline segment extending from Three Rivers to an interconnect with our South Texas Crude Oil Pipeline System in Wilson County. The Eagle Ford Crude Oil Pipeline System, which commenced operations in July 2013, currently has a transportation capacity of 300 MBPD and includes a marine barge terminal facility at Corpus Christi and 1.8 MMBbls of storage capacity across the system (0.9 MMBbls net to our ownership interest). Plains All American Pipeline, L.P. ("Plains"), our joint venture partner in the pipeline, serves as operator of the system.

In September 2013, we, along with Plains, announced an expansion of the Eagle Ford Crude Oil Pipeline System. This expansion project is expected to increase the pipeline system's capacity to transport light and

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medium grades of crude oil from 300 MBPD to 470 MBPD in order to accommodate expected volumes from Plains' Cactus pipeline. In addition, the joint venture will construct an additional 2.3 MMBbls of storage capacity at Gardendale, Tilden and Corpus Christi, Texas. In November 2014, we, along with Plains, announced a second major expansion project involving the Eagle Ford Crude Oil Pipeline System. This expansion project entails the construction of a new 55-mile crude oil gathering system that will connect Karnes County and Live Oak County production areas in Texas to the joint venture's Three Rivers terminal. The joint venture will also construct an additional 70-mile, 20-inch pipeline from Three Rivers to Corpus Christi as well as expand storage and pumping capacity at Three Rivers. When combined with the expansion project announced in September 2013, this project effectively loops the Eagle Ford Crude Oil Pipeline System from Gardendale to Corpus Christi and increases the system's capacity to transport light and medium grades of crude oil to over 600 MBPD. Both expansion projects are supported by long-term production commitments and are expected to be placed into service in the third quarter of 2015.

In November 2014, the joint venture also announced plans to construct a new deep water marine terminal on the Corpus Christi ship channel to support the expected increase in crude oil volumes to be shipped via pipeline to the region. The dock is being designed to handle a variety of ocean-going vessels and is expected to be in service by 2017.

Crude oil terminals. We own crude oil terminals located in Oklahoma (Cushing) and Texas (Houston and Midland) that are used to store crude oil for us and our customers. The results of operations from crude oil terminal services are primarily dependent upon the level of volumes a customer stores at each terminal and the length of time such storage occurs, including the level of firm storage capacity reserved (if any), pumpover volumes and the fees associated with each activity. Fees associated with firm storage capacity reservation agreements are charged regardless of the volume the customer actually stores at the terminal.

Historically, southeast Texas refineries have been supplied primarily by waterborne imports of crude oil. With the increase in North American production, crude oil from the Eagle Ford, Permian, Mid-Continent, Bakken and Canada is flowing into Southeast Texas and displacing waterborne crude oil imports. Due to growing domestic production, we expect a significant increase in North American crude oil deliveries to the Gulf Coast market, which currently lacks sufficient storage capacity and has an inadequate distribution system for handling these varying grades of domestic crude oil. In response, we are in the process of expanding our Oiltanking Houston and ECHO crude oil terminals (as described below). Upon completion of these expansion projects, we will be able to provide Gulf Coast refiners with an integrated system featuring supply diversification, significant storage capabilities and a high capacity pipeline distribution system that will be directly connected to customers having an aggregate refining capacity of approximately 3.9 MMBPD.

The following table presents selected information regarding our crude oil terminals at February 13, 2015:

		Our	Storage
		Ownership	Capacity
Description of Asset	Location(s)	Interest	(MMBbls)
Crude oil terminals:
Houston Ship Channel terminal	Texas	100.0%	20.1
ECHO terminal	Texas	Various (1)	3.0
Cushing terminal	Oklahoma	100.0%	3.3
Midland terminal	Texas	100.0%	1.4
Morgan's Point terminal	Texas	100.0%	0.3
Total			28.1

(1) We own 100% of six tanks at our ECHO terminal having a combined capacity of 2.0 MMBbls. Seaway owns two tanks at our ECHO terminal having a combined capacity of 1.0 MMBbls, of which we have an indirect 50% ownership interest through our equity method investment in Seaway.

The following information describes each of our principal crude oil storage terminals, all of which we operate.

§	The Houston Ship Channel terminal complex, which consists of Oiltanking's Jacintoport and Appelt terminals, is one of the largest such facilities on the Gulf Coast and provides terminaling services to major

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integrated oil companies, marketers, distributors and chemical companies. We acquired a controlling financial interest in Oiltanking on October 1, 2014 and completed the Oiltanking Merger on February 13, 2015. We now own 100% of the Houston Ship Channel terminal complex.

Our storage and distribution network is highly integrated with the greater Houston petrochemical and refining complex. As of December 31, 2014, crude oil and condensates accounted for approximately 82% of the terminal's active storage capacity, with refined products and specialty chemicals accounting for the remaining capacity. Substantially all of the terminal's current storage capacity of 20.1 MMBbls was under firm contract at December 31, 2014.

Our Houston Ship Channel terminal complex has extensive waterfront access, consisting of six deep-water ship docks and two barge docks. We can accommodate vessels with up to a 45 foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel. We believe that our location on the Houston Ship Channel to the east of the Beltway 8 Bridge enables us to handle larger vessels than our competitors who are located to the west of the Beltway 8 Bridge because our waterfront has fewer draft and beam restrictions.

The size and structure of our waterfront at the Houston facility allows us not only to receive and unload products for our storage customers, but also to provide third party docking services for which we receive throughput fees. Our LPG export and NGL import terminals, both of which are a component of our NGL Pipelines & Services business segment, are located at the Houston Ship Channel terminal complex.

We believe our Houston Ship Channel terminal complex is well positioned to take advantage of changing crude oil logistics along the Gulf Coast as a result of announced third party pipeline construction projects and waterborne and rail movements. In response, a number of expansion projects are underway at the Houston Ship Channel terminal complex. Since 2012, Oiltanking has announced expansion projects at our Appelt terminal totaling approximately 10.0 MMBbls of crude oil storage capacity, of which approximately 6.9 MMBbls has been placed into service as of December 31, 2014. We expect to place the remaining 3.1 MMBbls of crude oil storage capacity into service in the fourth quarter of 2015 and in the first quarter of 2016.

In addition to the Appelt projects, we are expanding the pipeline infrastructure associated with our Houston Ship Channel terminal to include connectivity with Crossroads Junction, which is the termination point of the Houston lateral of TransCanada Corporation's Gulf Coast Pipeline and the origination point of Shell Pipeline's Houston-to-Houma, or Ho-Ho, Pipeline. We completed a new 24-inch pipeline in late 2014 that provides our terminal customers direct access to the origination point of the Ho-Ho Pipeline, which transports crude oil from the Houston area eastbound to refining centers in Texas and Louisiana. We are constructing a 36-inch pipeline that will give our terminal customers access to the termination point of the Gulf Coast Pipeline, which is expected to connect to the Keystone XL pipeline if approved and constructed. We expect that the 36-inch pipeline will be completed by mid-2015.

The ECHO, or Enterprise Crude Houston, storage terminal is located in Houston, Texas and provides storage customers with access to major refineries located in the Houston and Texas City area. The ECHO terminal also has connections to marine facilities that provide connectivity to any refinery on the U.S. Gulf Coast. We developed the ECHO terminal to operationally support the expansion of our South Texas Crude Oil Pipeline System and Seaway Pipeline. Currently, we have 3.0 MMBbls of crude oil storage capacity at the ECHO terminal. This includes 1.1 MMBbls of storage capacity that we placed into service during 2014 and an additional 1.0 MMBbls (or 0.5 MMBbls net to our interest) that Seaway constructed, owns and placed into service at our ECHO terminal in January 2015.

In May 2013, we announced an expansion project at ECHO that would entail the construction of additional storage capacity. Also, we plan to construct 55 miles of associated pipelines to directly connect the ECHO storage facility with several major refineries in the Southeast Texas market. These expansion projects are expected to be completed in phases with final completion expected in the second quarter of 2015. At that time, we expect our ECHO terminal to have an aggregate crude oil storage capacity of 7.4 MMBbls.

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§	The Cushing terminal provides crude oil storage, pumpover and trade documentation services. Our terminal in Cushing, Oklahoma has an aggregate storage capacity of 3.3 MMBbls through the use of 20 above-ground storage tanks.

§	The Midland terminal provides crude oil storage, pumpover and trade documentation services. The Midland, Texas terminal has an aggregate storage capacity of 1.4 MMBbls through the use of 14 above-ground storage tanks.

Crude oil marketing activities. Our crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or from others on the open market. The results of operations from our crude oil marketing activities are primarily dependent upon the difference, or spread, between crude oil sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets. In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location or crude oil quality. We also use derivative instruments to mitigate our exposure to commodity price risks associated with our crude oil marketing activities.

U.S. federal law has prohibited the export of crude oil since the 1970s, except for crude oil sent to Canada. While untreated crude oil cannot be exported, refined products such as gasoline can be exported. Due to increasing U.S. crude oil production, producers have been lobbying the U.S. government to lift the ban on crude oil exports. Producers believe that fully lifting the ban will support domestic production efforts. In March 2014, the U.S. Department of Commerce ("Commerce Department") allowed us to begin exporting processed condensate, which is a type of ultralight crude oil that has been processed through a distillation facility. In December 2014, the Commerce Department granted permission for additional companies to begin exporting condensate. Our first condensate cargo was loaded in July 2014. In total, we loaded 3.7 MMBbls of condensate for export in 2014. We continue to monitor developments in this new business area.

Seasonality. Seasonality has little to no impact on the results of operations from our onshore crude oil pipelines and terminals. However, our crude oil assets situated along the Texas Gulf Coast (e.g., the Houston Ship Channel and ECHO terminals) may be affected by weather events such as hurricanes and tropical storms, which generally arise during the summer and fall months.

Competition. Within their respective market areas, our onshore crude oil pipelines, storage terminals and related marketing activities compete with other crude oil pipeline companies, rail carriers, major integrated oil companies and their marketing affiliates, financial institutions with trading platforms and independent crude oil gathering and marketing companies. The crude oil business can be characterized by strong competition for crude oil volumes. Competition is based primarily on quality of customer service, competitive pricing and proximity to customers and market hubs.

Offshore Pipelines & Services

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

Offshore natural gas and crude oil pipelines. Our offshore Gulf of Mexico pipelines provide for the gathering and transportation of natural gas or crude oil from offshore production fields to interconnecting offshore or onshore pipelines or processing facilities. The results of operations from these pipelines are primarily dependent upon the volume of natural gas or crude oil transported and the level of fees charged to shippers. Transportation fees are based either on contractual arrangements or, as in the case of our High Island Offshore System, tariffs regulated by the FERC. In general, contractual arrangements for offshore pipeline transportation services tend to be long-term in nature and involve life-of-reserve commitments.

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The following table presents selected information regarding our offshore natural gas pipelines at February 1, 2015:

	Our	Pipeline	Approximate
	Ownership	Length	Net Capacity
Description of Asset	Interest	(Miles)	(MMcf/d) (1)
Offshore natural gas pipelines:
Independence Trail	100.0%	135	1,000
Viosca Knoll Gathering System	100.0%	107	600
High Island Offshore System	100.0%	287	500
Falcon Natural Gas Pipeline	100.0%	14	400
Anaconda Gathering System	100.0%	183	300
Green Canyon Laterals	Various (2)	34	213
Manta Ray Offshore Gathering System	25.7% (3)	237	205
Nautilus System	25.7% (3)	101	154
VESCO Gathering System	13.1% (4)	125	65
Total		1,223

(1) Amounts presented are net to our ownership interest in the associated asset. (2) We proportionately consolidate our undivided interests, which range from 2.7% to 33.3%, in 28 miles of the Green Canyon Lateral pipelines. The remainder of the laterals are wholly owned. (3) Our ownership interests in the Manta Ray Offshore Gathering System and the Nautilus System are held indirectly through our equity method investment in Neptune Pipeline Company, L.L.C. ("Neptune"). (4) Our ownership interest in the VESCO Gathering System is held indirectly through our equity method investment in VESCO. We account for our investment in VESCO under the NGL Pipelines & Services business segment.

On a weighted-average basis, overall utilization rates for our offshore natural gas pipelines were approximately 16.3%, 17.7% and 21.7% during the years ended December 31, 2014, 2013 and 2012, respectively.

The following information describes each of our principal offshore natural gas pipelines. We operate our Independence Trail pipeline, Viosca Knoll Gathering System, High Island Offshore System, Falcon Natural Gas Pipeline, Anaconda Gathering System and certain components of the Green Canyon Laterals. Third parties operate the remainder of our offshore natural gas pipelines.

The Independence Trail pipeline transports natural gas from our Independence Hub platform and a pipeline interconnect downstream of our Independence Hub platform to the Tennessee Gas Pipeline at a pipeline interconnect on our West Delta 68 platform. Natural gas transported on the Independence Trail pipeline originates from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.

The Viosca Knoll Gathering System gathers natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico for delivery to several major interstate pipelines, including the High Point Gas Transmission, Transco, Dauphin Island Gathering System, Tennessee Gas Pipeline and Destin Pipelines.

The High Island Offshore System ("HIOS") transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of Mexico to interconnects with the ANR pipeline system and Tennessee Gas Pipeline. HIOS includes 201 miles of pipeline and eight pipeline junction and service platforms that are regulated by the FERC. In addition, this system includes the 86-mile East Breaks Gathering System, which connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25.

§	The Falcon Natural Gas Pipeline transports natural gas processed at our Falcon Nest platform to a connection with the Central Texas Gathering System located at the Brazos Addition Block 133 platform.

§	The Anaconda Gathering System gathers natural gas from producing fields located in the Green Canyon area of the Gulf of Mexico for delivery to our Nautilus System.

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§	The Green Canyon Laterals represent a collection of small diameter pipelines that gather natural gas for delivery to HIOS and various other downstream pipelines.

The Manta Ray Offshore Gathering System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for delivery to numerous downstream pipelines, including our Nautilus System. This system includes two pipeline junction platforms.

§	The Nautilus System connects our Anaconda Gathering System and Manta Ray Offshore Gathering System to our Neptune natural gas processing plant located in south Louisiana.

§	The VESCO Gathering System gathers natural gas from certain offshore developments for delivery to the Venice natural gas processing plant in south Louisiana.

The following table presents selected information regarding our offshore crude oil pipelines at February 1, 2015:

	Our		Approximate
	Ownership	Length	Net Capacity
Description of Asset	Interest	(Miles)	(MBPD) (1)
Offshore crude oil pipelines:
Shenzi Oil Pipeline	100.0%	83	230
Poseidon Oil Pipeline System	36.0% (2)	366	155
Cameron Highway Oil Pipeline	50.0% (3)	374	150
Allegheny Oil Pipeline	100.0%	40	140
Marco Polo Oil Pipeline	100.0%	37	120
Constitution Oil Pipeline	100.0%	67	80
SEKCO Oil Pipeline	50.0% (4)	145	58
Tarantula	100.0%	4	30
Total		1,116

(1) Amounts presented are net to our ownership interest in the associated asset. (2) Our ownership interest in the Poseidon Oil Pipeline System is held indirectly through our equity method investment in Poseidon Oil Pipeline Company, L.L.C. ("Poseidon"). (3) Our ownership interest in the Cameron Highway Oil Pipeline is held indirectly through our equity method investment in Cameron Highway Oil Pipeline Company ("Cameron Highway"). (4) Our ownership interest in the SEKCO Oil Pipeline is held indirectly through our equity method investment in Southeast Keathley Canyon Pipeline Company, L.L.C. ("SEKCO").

On a weighted-average basis, overall utilization rates for our offshore crude oil pipelines were approximately 35.9%, 31.3% and 30.6% during the years ended December 31, 2014, 2013 and 2012, respectively.

The following information describes each of our principal offshore crude oil pipelines, all of which we operate.

§	The Shenzi Oil Pipeline gathers crude oil production from the Shenzi production field located in the Green Canyon area of the Gulf of Mexico for delivery to both our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

§	The Poseidon Oil Pipeline System transports crude oil production from the outer continental shelf and deepwater areas of the Gulf of Mexico offshore Louisiana to onshore facilities in south Louisiana. This system includes one pipeline junction platform.

§	The Cameron Highway Oil Pipeline transports crude oil production from deepwater areas of the Gulf of Mexico, primarily the Green Canyon area, for delivery to refineries and terminals in southeast Texas. This system includes two pipeline junction platforms.

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§	The Allegheny Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

§	The Marco Polo Oil Pipeline transports crude oil from our Marco Polo oil platform to an interconnect with our Allegheny Oil Pipeline in Green Canyon Block 164.

§	The Constitution Oil Pipeline gathers crude oil from the Constitution, Caesar Tonga and Ticonderoga production fields located in the Green Canyon area of the Gulf of Mexico for delivery to either our Cameron Highway Oil Pipeline or Poseidon Oil Pipeline System.

The SEKCO Oil Pipeline connects the third party-owned Lucius-truss spar floating production platform to an existing junction platform at South Marsh Island 205, which is part of our Poseidon Oil Pipeline System. The SEKCO Oil Pipeline was completed and started earning firm capacity reservation fees in July 2014. Crude oil shipments commenced in January 2015 when the Lucius oil and gas field started operations.

Offshore hub platforms. Offshore hub platforms are important components of our pipeline operations in the Gulf of Mexico. These platforms are typically used to interconnect the offshore pipeline network; provide an efficient means to perform pipeline maintenance; locate compression, separation and production handling equipment and similar assets; and conduct drilling operations during the initial development phase of an oil and natural gas property.

The results of operations from offshore platform services are primarily dependent upon the level of commodity charges and/or demand-type fees billable to customers. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform (typically per MMcf of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered. Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a customer regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include both demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers.

The following table presents selected information regarding our offshore hub platforms at February 1, 2015:

	Our	Water	Approximate Net Capacity (1)
	Ownership	Depth	Natural Gas	Crude Oil
Description of Asset	Interest	(Feet)	(MMcf/d)	(MBPD)
Offshore hub platforms:
Independence Hub	80.0% (2)	8,000	800	N/A
Marco Polo	50.0% (3)	4,300	150	60
Viosca Knoll 817	100.0%	671	145	5
Garden Banks 72	50.0% (4)	518	113	18
East Cameron 373	100.0%	441	195	3
Falcon Nest	100.0%	389	400	3

(1) Amounts presented are net to our ownership interest. (2) We own an 80% consolidated interest in the Independence Hub platform through our majority owned subsidiary, Independence Hub, LLC. (3) Our ownership interest in the Marco Polo platform is held indirectly through our equity method investment in Deepwater Gateway, L.L.C. ("Deepwater Gateway"). (4) We proportionately consolidate our undivided interest in the Garden Banks 72 platform.

In addition to our offshore hub platforms, we also own or indirectly own, through our equity method investees, 15 pipeline junction and service platforms (12 of which we operate). Unlike hub platforms, pipeline junction and service platforms do not have processing capacity.

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With respect to natural gas processing capacity, the overall utilization rates (on a weighted-average basis) of our offshore hub platforms were approximately 8.1%, 11.2% and 16.2% during the years ended December 31, 2014, 2013 and 2012, respectively. With respect to crude oil processing capacity, the overall utilization rates (on a weighted-average basis) of our offshore platforms were approximately 16.9%, 17.5% and 18.9% during the years ended December 31, 2014, 2013 and 2012, respectively.

The following information describes each of our principal Gulf of Mexico offshore hub platforms. We operate these platforms with the exception of the Independence Hub and Marco Polo platforms.

§	The Independence Hub platform is located in Mississippi Canyon Block 920. This platform processes natural gas gathered from deepwater production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.

§	The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of Mexico.

§	The Viosca Knoll 817 platform primarily serves as a base for gathering deepwater production in the Viosca Knoll area, including the Ram Powell development.

§	The Garden Banks 72 platform serves as a base for gathering deepwater production from the Garden Banks area of the Gulf of Mexico. This platform also serves as a junction platform for our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.

§	The East Cameron 373 platform processes production from the Garden Banks and East Cameron areas of the Gulf of Mexico.

§	The Falcon Nest platform, which is located in the Mustang Island East area of the Gulf of Mexico, processes natural gas from the Falcon field.

Seasonality. Our offshore operations exhibit little to no effects of seasonality; however, they may be affected by weather events such as hurricanes and tropical storms in the Gulf of Mexico, which generally arise during the summer and fall months. See Note 19 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding weather-related risks and insurance matters.

Competition. Within their respective market areas, our offshore pipelines compete with other offshore pipelines primarily on the basis of fees charged, available throughput capacity, connections to downstream markets and proximity and access to existing reserves.

Petrochemical & Refined Products Services

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

Propylene fractionation and related operations. Our propylene fractionation and related operations consist of seven propylene fractionation plants, including pipeline systems aggregating approximately 680 miles in length, and related petrochemical marketing activities. This business includes an export facility and associated above-ground storage spheres for polymer grade propylene located in Seabrook, Texas. We operate all of our propylene fractionation and related assets except for the Lake Charles Pipeline in Louisiana.

In general, propylene fractionation plants separate refinery grade propylene, which is a mixture of propane and propylene, into either polymer grade propylene or chemical grade propylene along with by-products of propane and mixed butane. Polymer grade and chemical grade propylene can also be produced as a by-product of ethylene production. The demand for polymer grade propylene primarily relates to the manufacture of polypropylene, which

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has a variety of end uses including packaging film, fiber for carpets and upholstery and molded plastic parts for appliances and automotive, houseware and medical products. Chemical grade propylene is a basic petrochemical used in the manufacturing of plastics, synthetic fibers and foams.

The results of operations from propylene fractionation are generally dependent upon toll processing arrangements with customers and our petrochemical marketing activities. Toll processing arrangements typically include a base processing fee per gallon (or other unit of measurement) subject to adjustment for changes in power, fuel and labor costs, all of which are the primary costs of propylene fractionation activities. The results of operations from our petrochemical pipelines are primarily dependent upon the volume of products transported and the level of fees charged to shippers. Transportation fees are based on contractual arrangements and may include provisions whereby the customer pays us a fee if certain volume thresholds are not met over a contractual term.

In our petrochemical marketing activities, we purchase refinery grade propylene on the open market for fractionation at our facilities and sell the resulting products at market-based prices. The selling price of these products may include pricing differentials for factors such as delivery location. The results of operations from our petrochemical marketing activities are primarily dependent upon the difference, or spread, between the sales prices of the products and associated purchase and other costs, including those costs attributable to the use of our other assets. As part of our petrochemical marketing activities, we have several long-term refinery grade propylene purchase and polymer grade propylene sales agreements. In order to limit the exposure of our petrochemical marketing activities to commodity price risk, we attempt to match the timing and price of our feedstock purchases with those of the sales of end products.

The following table presents selected information regarding our propylene fractionation facilities at February 1, 2015:

		Our	Net Plant	Total Plant
		Ownership	Capacity	Capacity
Description of Asset	Location(s)	Interest	(MBPD)	(MBPD)
Propylene fractionation facilities:
Mont Belvieu (six units)	Texas	Various (1)	81	95
BRPC (one unit)	Louisiana	30.0% (2)	7	23
Total			88	118

(1) We proportionately consolidate a 66.7% undivided interest in three of the propylene fractionation units, which have an aggregate 41 MBPD of total plant capacity. The remaining three propylene fractionation units are wholly owned. (2) Our ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC ("BRPC").

We produce polymer grade propylene at our Mont Belvieu, Texas propylene fractionation facility and chemical grade propylene at our BRPC facility located in Baton Rouge, Louisiana. On a weighted-average basis, overall utilization rates of our propylene fractionation facilities were approximately 84.7%, 87.4% and 87.8% during the years ended December 31, 2014, 2013 and 2012, respectively.

This business includes a marine export facility located on the Houston Ship Channel at Seabrook, Texas that can load vessels at rates up to 5,000 barrels per hour. This export facility also includes above-ground storage spheres for polymer grade propylene. A renovation of this facility is expected to be completed in the second quarter of 2015.

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The following table presents selected information regarding our petrochemical pipelines at February 1, 2015:

		Ownership	Length
Description of Asset	Location(s)	Interest	(Miles)
Petrochemical pipelines:
Lou-Tex and Sabine Propylene	Texas, Louisiana	100.0%	278
Texas City RGP Gathering System	Texas	100.0%	171
North Dean Pipeline System	Texas	100.0%	149
Propylene Splitter PGP Distribution System	Texas	100.0%	34
Lake Charles PGP Pipeline	Louisiana	50.0% (1)	26
La Porte PGP Pipeline	Texas	50.0% (2)	20
Total			678

(1) We proportionately consolidate our undivided interest in the Lake Charles PGP Pipeline. (2) Our ownership interest in the La Porte PGP Pipeline is held indirectly through our equity method investments in La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C.

The Lou-Tex Propylene pipeline is used to transport chemical grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas. The Sabine pipeline is used to transport polymer grade propylene from Port Arthur, Texas to a delivery point in Cameron Parish, Louisiana. The North Dean Pipeline System transports refinery grade propylene from Mont Belvieu, Texas, to Point Comfort, Texas. The remainder of our petrochemical pipelines primarily transport refinery grade propylene or polymer grade propylene for customers in southeast Texas and southwest Louisiana.

The maximum number of barrels per day that our petrochemical pipelines can transport depends on the operating balance achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the mix of products being transported). As a result, we measure the utilization rates of our petrochemical pipelines in terms of net throughput, which is based on our ownership interest. Total net throughput volumes were 124 MBPD, 118 MBPD and 117 MBPD during the years ended December 31, 2014, 2013 and 2012, respectively.

In June 2012, we announced plans to build a propane dehydrogenation ("PDH") facility, with capacity to produce up to 1.65 billion pounds per year (or approximately 750 thousand metric tons per year or 25 MBPD) of polymer grade propylene. The PDH facility is expected to consume approximately 35 MBPD of propane as feedstock and be located adjacent to our Mont Belvieu complex. The new facility will be integrated with our existing propylene fractionation facilities, which will provide operational reliability and flexibility for both the PDH facility and the fractionation facilities. The PDH facility will also be integrated with our polymer grade propylene storage facilities, pipeline system and export terminal. The PDH facility, which is supported by long-term, fee-based contracts, is expected to begin commercial operations during the fourth quarter of 2016.

Butane isomerization and deisobutanizer operations. Our Mont Belvieu complex includes three isomerization units and nine deisobutanizer ("DIB") units. Each of our isomerization units includes two reactors that convert normal butane feedstock into mixed butane, which is a stream of isobutane and normal butane. DIBs then separate the isobutane from the normal butane through fractionation. Any remaining unconverted (or residual) normal butane generated by the DIB process is then recirculated through the isomerization process until it has been converted into varying grades of isobutane, including high-purity isobutane. The isomerization process also produces natural gasoline as a by-product. We also use our DIB units to fractionate mixed butane produced from our NGL fractionators and other sources into isobutane and normal butane. Our butane isomerization assets comprise the largest commercial isomerization facility in the U.S. These operations include a 70-mile pipeline system used to transport high-purity isobutane from Mont Belvieu, Texas to Port Neches, Texas. We own and operate our butane isomerization facility and related pipeline assets.

The primary uses of isobutane are for the production of propylene oxide, isooctane, isobutylene and alkylate for motor gasoline. The demand for commercial isomerization services depends upon the industry's requirements for isobutane and high-purity isobutane in excess of the isobutane produced through the process of NGL fractionation and refinery operations. The processing capacity of our isomerization facility is 116 MBPD. On

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a weighted-average basis, utilization rates for this facility were approximately 80.2%, 81.0% and 81.9% during the years ended December 31, 2014, 2013 and 2012, respectively.

We use certain DIB units to fractionate mixed butanes produced from our NGL fractionation activities, from imports and from other sources into isobutane and normal butane. The operating flexibility provided by our multiple standalone DIBs enables us to take advantage of fluctuations in demand and prices for different types of butane. We measure the utilization of our standalone DIB units in terms of processing volumes, which averaged 82 MBPD, 67 MBPD and 46 MBPD for the years ended December 31, 2014, 2013 and 2012, respectively. Standalone DIB processing volumes have increased as a result of increased NGL fractionation volumes at our Mont Belvieu complex.

The results of operation of this business are generally dependent on the volume of normal and mixed butanes processed, the level of toll processing fees charged to customers and prices received for by-products. These processing arrangements typically include a base-processing fee per gallon (or other unit of measurement) subject to adjustment for changes in power, fuel and labor costs, all of which are the primary costs of isomerization. These assets provide processing services to meet the needs of third party customers and our other businesses, including our NGL marketing activities and octane enhancement production facility. Our isomerization business also generates revenues from the sale of natural gasoline created as a by-product of the underlying processes.

Octane enhancement and high purity isobutylene production facilities. We own and operate an octane enhancement production facility located in Mont Belvieu, Texas that is designed to produce isooctane, isobutylene and methyl tertiary butyl ether ("MTBE"). The products produced by this facility are used in reformulated motor gasoline blends to increase octane values. The high-purity isobutane feedstocks consumed in the production of these products are supplied by our isomerization units.

In general, we sell our octane enhancement products at market-based prices. We attempt to mitigate the price risk associated with these products by entering into commodity derivative instruments. To the extent that we produce MTBE, it is sold exclusively into the export market. The production capacity of our octane enhancement facility is 12 MBPD of isooctane or 15.5 MBPD of MTBE. On a weighted-average basis, utilization rates for our octane enhancement facility were approximately 51.6%, 90.3% and 71% during the years ended December 31, 2014, 2013 and 2012, respectively. Our octane enhancement facility operated at lower utilization rates in 2014 primarily due to mechanical restrictions. These restrictions are expected to be remedied during the facility's annual turnaround in the first quarter of 2015.

We also own a facility located on the Houston Ship Channel that produces up to 4 MBPD of high purity isobutylene ("HPIB") and includes an associated storage facility with 0.6 MMBbls of storage capacity, 0.2 MMBbls of which is pressurized storage. The primary feedstock for this plant, an isobutane/isobutylene mix, is produced by our Mont Belvieu octane enhancement facility. HPIB is used in the formulation of polyisobutylene, which is used in the manufacture of lubricants and rubber. In general, we sell HPIB at market-based prices with a cost-based floor. On a weighted-average basis, utilization rates for this facility were 47.2%, 40.6% and 39.5% for the years ended December 31, 2014, 2013 and 2012, respectively.

Refined products pipelines. Refined products pipelines include our TE Products Pipeline and an investment in Centennial Pipeline LLC ("Centennial"). The refined petroleum products (or "refined products") transported by these pipelines are produced by refineries and primarily include motor gasoline. The results of operations for these pipelines are primarily dependent upon the volume of products transported and the level of fees charged to shippers. The tariffs charged for such services are either contractual or regulated by governmental agencies, including the FERC.

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The following table presents selected information regarding our refined products pipelines and related terminal and storage assets at February 1, 2015:

				Net Usable
		Our		Storage
		Ownership	Length	Capacity
Description of Asset	Location(s)	Interest	(Miles)	(MMBbls)
Refined products pipelines and terminals:
TE Products Pipeline (1,2)	Texas to Midwest and Northeast U.S.	100.0%	3,403	18.2
Centennial Pipeline (2)	Texas to Illinois	50.0% (3)	795	1.2
Total			4,198	19.4

(1) In addition to the 18.2 MMBbls of refined products storage capacity presented in the table, we have 3.7 MMBbls of storage capacity that is used to support NGL operations on our TE Products Pipeline. Our NGL storage and terminal assets are accounted for under the NGL Pipelines & Services business segment. (2) Interstate and intrastate transportation services provided by the TE Products Pipeline and interstate transportation services provided by the Centennial Pipeline are regulated by governmental agencies. (3) Our ownership interest in the Centennial Pipeline is held indirectly through our equity method investment in Centennial.

The maximum number of barrels per day that our refined products pipelines can transport depends on the operating balance achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the mix of products being transported). As a result, we measure the utilization rates of our refined products pipelines in terms of net throughput, which is based on our ownership interest. Aggregate net throughput volumes by product type for the TE Products Pipeline and Centennial Pipeline were as follows for the periods presented:

	For Year Ended December 31,
	2014		2013		2012
Refined products transportation (MBPD)		412		373		383
Petrochemical transportation (MBPD)		137		120		101
NGL transportation (MBPD)		65		72		66

Due to increased refinery production in the Midwest and Northeast U.S. and lower overall demand for refined products in these regions, demand for refined products produced along the Gulf Coast has decreased. In response, we repurposed significant components of our TE Products Pipeline for use by the ATEX pipeline to accommodate the southbound delivery of ethane produced from the Marcellus and Utica Shale formations.

As noted previously, these pipelines are subject to regulation. See "Regulatory Matters" within this Part I, Item 1 and 2 discussion for additional information regarding governmental oversight of liquids pipelines, including tariffs charged for transportation services.

The following information describes each of our principal refined products pipelines. We operate the TE Products Pipeline system and our joint venture partner in Centennial operates the Centennial Pipeline.

The TE Products Pipeline is a 3,403-mile pipeline system comprised of 3,085 miles of interstate pipelines and 318 miles of intrastate Texas pipelines. Refined products and certain NGLs are transported from the upper Texas Gulf Coast to Seymour, Indiana. From Seymour, segments of the TE Products Pipeline extend to Chicago, Illinois; Lima, Ohio; Selkirk, New York; and near Philadelphia, Pennsylvania. East of Seymour, Indiana, the TE Products Pipeline is primarily dedicated to NGL transportation service.

Products are delivered to various locations along the system, including terminals owned either by us or third parties and to various connecting pipelines. We own and operate five refined products truck terminals and various storage facilities located along the TE Products Pipeline.

In January 2014, our ATEX pipeline commenced operations. In addition to new construction, this project involved repurposing components of the TE Products Pipeline to accommodate southbound delivery of ethane to the U.S. Gulf Coast. The repurposed pipeline assets were reclassified to the NGL Pipelines & Services business segment (on a prospective basis in January 2014) when ATEX commenced operations.

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TE Products Pipeline assets that were not repurposed remain in the Petrochemical & Refined Products Services business segment.

The Centennial Pipeline is a refined products pipeline that extends from an origination facility located on our TE Products Pipeline in Beaumont, Texas, to Bourbon, Illinois. The Centennial Pipeline includes a refined products storage terminal located near Creal Springs, Illinois with a gross storage capacity of 2.3 MMBbls (or 1.2 MMBbls net to our ownership interest).

Refined products terminals. We own a refined products storage terminal and export facility located in Beaumont, Texas and refined products marketing and distribution terminals located in Alabama and Mississippi. The results of operations from our refined products terminaling services are primarily dependent upon the level of volumes a customer stores at each terminal and the length of time such storage occurs, including the level of firm storage capacity reserved (if any), pumpover volumes and the fees associated with each activity. Fees associated with firm storage capacity reservation agreements are charged regardless of the volume the customer actually stores at the terminal. The results of operations from our refined products export facility are primarily dependent upon the volume handled and the associated fees we charge for loading services. Revenue is recorded in the period the export services are provided. Customers are typically billed a fee per unit of volume loaded. With respect to our export terminal operations, revenue may also include deficiency fees charged to customers that reserve capacity at our export facility and later fail to use such capacity. Deficiency fee revenue is recognized when the customer fails to utilize the specified export capacity as required by contract.

The following information describes our Beaumont refined products storage terminal and export facility, which are the principal assets classified in this business. We operate both assets.

The Beaumont West Terminal complex, which consists of Oiltanking's Beaumont operations, has 5.5 MMBbls of storage capacity and serves as a regional strategic and trading hub for refined petroleum products. We acquired a controlling financial interest in Oiltanking on October 1, 2014 and completed the Oiltanking Merger on February 13, 2015. We now own 100% of the Beaumont West Terminal.

Located on the Neches River near Beaumont, Texas, our Beaumont West Terminal is integrated with the Beaumont/Port Arthur petrochemical and refining complex, and provides customers with additional services, such as mixing, blending, heating and marine vapor recovery. As of December 31, 2014, refined products accounted for approximately 88% of the terminal's active storage capacity, with specialty chemicals accounting for the remaining capacity. Substantially all of the terminal's current storage capacity of 5.5 MMBbls was under firm contract at December 31, 2014.

Waterfront capabilities at our Beaumont West Terminal currently consist of two deep-water ship docks that can accommodate vessels with drafts of up to 40 feet, and two barge docks that can accommodate vessels with drafts of up to 12 feet.

Our Beaumont facility handles products through a number of transportation modes, including third party pipelines interconnected to local refineries and production facilities, our dedicated pipeline system to a customer's chemical production facility located in Port Neches, Texas, and third party ships and barges arriving at our deep-water docks.

In June 2014, Oiltanking announced the approval of a project at this terminal to construct new storage tanks, pipelines and dock infrastructure to serve crude oil customers. This multi-phase project is expected to have a total capacity of up to 6.2 MMBbls of crude oil storage when all currently planned phases have been completed. The first phase includes pipeline connections and manifold infrastructure and the construction of a new finger pier with two new deep-water docks. The new docks will be configured to load and unload crude oil and related products at rates sufficient to accommodate expected growth at the terminal. We anticipate that the first storage tanks will be placed into service by the third quarter of 2015. When completed, we expect to classify the crude oil assets within our Onshore Crude Oil Pipelines & Services business segment.

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Our Beaumont Refined Products Export Terminal, located on the Neches River, can load cargoes at rates up to 15,000 barrels per hour. The facility includes a dock with a 40-foot draft that can accommodate Panamax size vessels that have a capacity of up to 400,000 barrels. The terminal receives products from eight refineries, representing approximately 3.3 MMBPD of capacity, as well as our TE Products Pipeline and the third party-owned Colonial Pipeline. This terminal has access to more than 12.0 MMBbls of refined products storage including capacity at our Beaumont West Terminal (see above) and 3.0 MMBbls of storage capacity located along our TE Products Pipeline in Beaumont, Texas.

In May 2014, we began loading cargoes of refined products for export at the terminal, which was previously inactive, with the dock operating on a reservation basis. The facility was fully subscribed within the first six months of operations. We are also expanding the terminal with additional on-site storage and ancillary equipment for gasoline blending operations. Reactivation of the terminal, as well as its expansion, was supported by long-term customer commitments. With its strategic location and enhanced capabilities, the Beaumont Refined Products Export Terminal provides optionality for exporters, allowing them to capture added value from the evolving fundamentals of the domestic and international refined products markets while avoiding the long wait times associated with Houston Ship Channel refined products export facilities.

Refined products marketing activities. Our refined products marketing activities generate revenues from the sale and delivery of refined products obtained on the open market. The results of operations from our refined products marketing activities are primarily dependent upon the difference, or spread, between product sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets. In general, we sell our refined products at market-based prices, which may include pricing differentials for factors such as delivery location. We use derivative instruments to mitigate our exposure to commodity price risks associated with our refined products marketing activities.

Marine transportation. Our marine transportation business consists of tow boats and tank barges that are used to transport refined products, crude oil, asphalt, condensate, heavy fuel oil, liquefied petroleum gas and other petroleum products along key inland and intracoastal U.S. waterways. The marine transportation industry uses tow boats as power sources and tank barges for freight capacity. We refer to the combination of the power source and freight capacity as a tow. Our inland tows generally consist of one tow boat paired with up to four tank barges, depending upon the horsepower of the tow boat, location, waterway conditions, customer requirements and prudent operational considerations. Our offshore tows generally consist of one tow boat and one ocean-certified tank barge.

Our marine transportation assets service refinery and storage terminal customers along the Mississippi River, the intracoastal waterway between Texas and Florida and the Tennessee-Tombigbee Waterway system. We own a shipyard and repair facility located in Houma, Louisiana and marine fleeting facilities located in Bourg, Louisiana and Channelview, Texas. The results of operations of our marine transportation business are generally dependent upon the level of fees charged to transport cargo. These transportation services are typically provided under term contracts (also referred to as affreightment contracts), which are agreements with specific customers to transport cargo from within designated operating areas at either set day rates or a set fee per cargo movement.

Our marine transportation business is subject to regulation by the U.S. Department of Transportation ("DOT"), Department of Homeland Security, U.S. Department of Commerce and the U.S. Coast Guard ("USCG") and federal and state laws. For additional information regarding these regulations, see "Regulatory Matters – Federal Regulation of Marine Operations," within this Part I, Item 1 and 2 discussion.

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The following table presents selected information regarding our marine transportation assets at February 1, 2015:

Class of Equipment	Number in Class	Capacity/ Horsepower (as indicated by sign) (1)
Inland marine transportation assets:
Barges	9	< 25,000 bbls
Barges	115	> 25,000 bbls
Tow boats	18	< 2,000 hp
Tow boats	40	≥ 2,000 hp
Offshore marine transportation assets:
Ocean-certified tank barges	7	≥ 20,000 bbls
Tow boats	5	≥ 2,000 hp

(1) As used in this table, references to "bbls" means barrels and "hp" means horsepower.

Our fleet of marine vessels operated at an average utilization rate of 93.1%, 93.9% and 90.9% during the years ended December 31, 2014, 2013 and 2012, respectively.

Seasonality. Overall, the propylene fractionation business exhibits little seasonality. Our isomerization operations experience slightly higher levels of demand in the spring and summer months due to increased demand for isobutane-based fuel additives used in the production of motor gasoline. Likewise, octane additive prices have been stronger from April to September of each year when motor gasoline demand increases in connection with the summer driving season.

Our refined products pipelines and related activities exhibit seasonality based upon the mix of products delivered and the weather and economic conditions in the geographic areas being served. Refined products volumes are generally higher during the second and third quarters of each year because of greater demand for motor gasoline during the spring and summer driving seasons. NGL transportation volumes on the TE Products Pipeline are generally higher from October through March due to higher demand for propane (for residential heating purposes) and normal butane (for blending in motor gasoline).

Our marine transportation business exhibits some seasonal variation. Demand for motor gasoline is generally stronger in the spring and summer months due to the summer driving season. Weather events, such as hurricanes and tropical storms in the Gulf of Mexico, can adversely impact both the offshore and inland marine transportation business. Also, cold weather and ice during the winter months can negatively impact our inland marine operations on the upper Mississippi and Illinois rivers.

Competition. We compete with numerous producers of polymer grade propylene, which include many of the major refiners and petrochemical companies located along the Gulf Coast. Generally, our propylene fractionation business competes in terms of the level of toll processing fees charged and access to pipeline and storage infrastructure. Our petrochemical marketing activities encounter competition from fully integrated oil companies and various petrochemical companies. Our petrochemical marketing competitors have varying levels of financial and personnel resources and competition generally revolves around price, quality of customer service, logistics and location.

With respect to our isomerization operations, we compete primarily with facilities located in Kansas, Louisiana and New Mexico. Competitive factors affecting this business include the level of toll processing fees charged, the quality of isobutane that can be produced and access to supporting pipeline and storage infrastructure. We compete with other octane additive manufacturing companies primarily on the basis of price.

With respect to our TE Products Pipeline, its most significant competitors are third party pipelines in the areas where it delivers products. Competition among common carrier pipelines is based primarily on transportation fees, quality of customer service and proximity to end users. Trucks, barges and railroads competitively deliver products into some of the markets served by our TE Products Pipeline and river terminals. The TE Products

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Pipeline faces competition from rail and pipeline movements of NGLs from Canada and waterborne imports into terminals located along the upper East Coast.

Our marine transportation business competes with other inland marine transportation companies as well as providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines. Competition within the marine transportation business is largely based on price.

Title to Properties

Our real property holdings fall into two basic categories: (i) parcels that we and our unconsolidated affiliates own in fee (e.g., we own the land upon which our Mont Belvieu NGL fractionators are constructed) and (ii) parcels in which our interests and those of our affiliates are derived from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. The fee sites upon which our significant facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites. We and our affiliates have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our rights pursuant to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory rights pursuant to all of our material leases, easements, rights-of-way, permits and licenses.

Regulatory Matters

The following information describes the principal effects of regulation on our business activities, including those regulations involving safety and environmental matters and the rates we charge customers for transportation services.

Safety Matters

The safe operation of our pipelines and other assets is a top priority of our partnership. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner.

Occupational Safety and Health. Certain of our facilities are subject to the general industry requirements of the Federal Occupational Safety and Health Act, as amended ("OSHA"), and comparable state statutes. We believe we are in material compliance with OSHA and the similar state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures of employees.

Certain of our facilities are subject to OSHA Process Safety Management ("PSM") regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process involving a chemical at or above a specified threshold (as defined in the regulations) or any process which involves certain flammable gases or liquids. In addition, we are subject to the Risk Management Plan regulations of the U.S. Environmental Protection Agency ("EPA") at certain facilities. These regulations are intended to complement the OSHA PSM regulations. These EPA regulations require us to develop and implement a risk management program that includes a five-year accident history report, an offsite consequence analysis process, a prevention program and an emergency response program. We believe we are operating in material compliance with the OSHA PSM regulations and the EPA's Risk Management Plan requirements.

The OSHA hazard communication standard, the community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to federal, state and local governmental authorities and local citizens upon request. These laws and provisions of the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") require us to report spills and releases of hazardous chemicals in certain situations.

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Pipeline Safety. We are subject to extensive regulation by the U.S. DOT authorized under various provisions of Title 49 of the United States Code and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. These statutes require companies that own or operate pipelines to (i) comply with such regulations, (ii) permit access to and copying of pertinent records, (iii) file certain reports and (iv) provide information as required by the U.S. Secretary of Transportation. We believe we are in material compliance with these DOT regulations.

We are subject to DOT pipeline integrity management regulations that specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas ("HCAs"). HCAs include populated areas, unusually sensitive areas and commercially navigable waterways. The regulation requires the development and implementation of an integrity management program that utilizes internal pipeline inspection techniques, pressure testing or other equally effective means to assess the integrity of pipeline segments in HCAs. These regulations also require periodic review of HCA pipeline segments to ensure that adequate preventative and mitigative measures exist and that companies take prompt action to address integrity issues raised in the assessment and analysis process. We have identified our pipeline segments in HCAs and developed an appropriate integrity management program for such assets.

In January 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the "2011 Pipeline Safety Act"). This act provides for additional regulatory oversight of the nation's pipelines, increases the penalties for violations of pipeline safety rules, and complements the DOT's other initiatives. The 2011 Pipeline Safety Act increases the maximum fine for the most serious pipeline safety violations involving deaths, injuries or major environmental harm from $1 million to $2 million. In addition, this law established additional safety requirements for newly constructed pipelines. The law also provides for (i) additional pipeline damage prevention measures, (ii) allowing the Secretary of Transportation to require automatic and remote-controlled shut-off valves on new pipelines, (iii) requiring the Secretary of Transportation to evaluate the effectiveness of expanding pipeline integrity management and leak detection requirements, (iv) improving the way the DOT and pipeline operators provide information to the public and emergency responders and (v) reforming the process by which pipeline operators notify federal, state and local officials of pipeline accidents.

In total, our pipeline integrity costs for the years ended December 31, 2014, 2013 and 2012 were $99.0 million, $128.0 million and $150.0 million, respectively. Of these annual totals, we charged $59.7 million, $70.4 million and $70.6 million to operating costs and expenses during the years ended December 31, 2014, 2013 and 2012, respectively. The remaining annual pipeline integrity costs were capitalized and treated as sustaining capital projects. We expect the cost of our pipeline integrity program, regardless of whether such costs are capitalized or expensed, to approximate $128.0 million for 2015.

DOT regulations have incorporated by reference, the American Petroleum Institute Standard 653 ("API 653") as the industry standard for the inspection, repair, alteration and reconstruction of storage tanks. API 653 requires regularly scheduled inspection and repair of such tanks. These periodic tank maintenance requirements may result in significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our storage tanks.

In January 2015, the White House announced plans to regulate methane emissions attributable to the upstream oil and gas industry, including activities related to gathering and compression, as a greenhouse gas. See "Climate Change Debate" within this Regulatory Matters section. This announcement indicated that the DOT through its Pipeline and Hazardous Materials Safety Administration, or PHMSA, will be issuing new natural gas regulations with the intent to improve safety as well as to reduce methane emissions. Until such proposed rules are developed and published, the impact on our operations is not known.

Environmental Matters

Our operations are subject to various environmental and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. These include, without limitation: CERCLA; the Resource Conservation and Recovery Act ("RCRA"); the Federal Clean Air Act ("CAA"); the Clean Water Act ("CWA"); the Oil Pollution Act of 1990 ("OPA"); OSHA; the Emergency Planning and Community Right to Know Act; and comparable or analogous state and local laws and regulations. Such laws and regulations affect many aspects of our

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present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals with respect to air emissions, water quality, wastewater discharges and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.

If a leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, we could be required to remove previously disposed waste products or remediate contaminated property, including situations where groundwater has been impacted. Any or all of these developments could have a material adverse effect on our financial position, results of operations and cash flows.

We believe our operations are in material compliance with applicable environmental and safety laws and regulations. In addition, we expect that compliance with existing environmental and safety laws and regulations will not have a material adverse effect on our financial position, results of operations and cash flows. However, environmental and safety laws and regulations are subject to change. The trend in environmental regulation has been to place more restrictions and limitations on activities that may be perceived to impact the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. New or revised regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our financial position, results of operations and cash flows.

On occasion, we are assessed monetary sanctions by governmental authorities related to administrative or judicial proceedings involving environmental matters. See Part I, Item 3 of this annual report for additional information.

Air Quality. Our operations are associated with regulatory permitted emissions of air pollutants. As a result, we are subject to the CAA and comparable state laws and regulations including state air quality implementation plans. These laws and regulations regulate emissions of air pollutants from various industrial sources, including certain of our facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and strictly comply with the requirements of air permits containing various emission and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions. We may be required to incur certain capital expenditures for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Water Quality. The CWA and comparable state laws impose strict controls on the discharge of crude oil and its derivatives into regulated waters. The CWA provides penalties for any discharge of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing petroleum or other hazardous substances. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in navigable waters or into groundwater. Spill prevention control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent a petroleum tank release from impacting regulated waters. The EPA has also adopted regulations that require us to have permits in order to discharge certain storm water run-off. Storm water discharge permits may also be required by certain states in which we operate and may impose certain monitoring and other requirements. The CWA further prohibits discharges of dredged and fill material in wetlands and other waters of the U.S. unless authorized by an appropriately issued permit. We believe that our costs of compliance with these CWA requirements will not have a material adverse effect on our financial position, results of operations and cash flows.

The primary federal law for crude oil spill liability is the OPA, which addresses three principal areas of crude oil pollution: prevention, containment and clean-up and liability. The OPA applies to vessels, offshore

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platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport crude oil above certain thresholds, onshore facilities are required to file oil spill response plans with the USCG, the DOT's OPS or the EPA, as appropriate. Numerous states have enacted laws similar to the OPA. Under the OPA and similar state laws, responsible parties for a regulated facility from which crude oil is discharged may be liable for remediation costs, including damage to surrounding natural resources. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remediation costs.

Contamination resulting from spills or releases of petroleum products is an inherent risk within the pipeline industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems or other facilities as a result of past operations, we believe any such contamination could be controlled or remedied without having a material adverse effect on our financial position, results of operations and cash flows, but such costs are site specific and there is no assurance that the impact will not be material in the aggregate.

Environmental groups have instituted lawsuits regarding certain nationwide permits issued by the Army Corps of Engineers. These permits allow for streamlined permitting of pipeline projects. If these lawsuits are successful, timelines for future pipeline construction projects could be adversely impacted.

Disposal of Hazardous and Non-Hazardous Wastes. In our normal operations, we generate hazardous and non-hazardous solid wastes that are subject to requirements of the federal RCRA and comparable state statutes, which impose detailed requirements for the handling, storage, treatment and disposal of solid waste. We also utilize waste minimization and recycling processes to reduce the volumes of our solid wastes.

CERCLA, also known as "Superfund," imposes liability, often without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a facility. Under CERCLA, responsible parties may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and RCRA also authorize the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible parties. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, our pipeline systems and other facilities generate wastes that may fall within CERCLA's definition of a "hazardous substance" or be subject to CERCLA and RCRA remediation requirements. It is possible that we could incur liability for remediation or reimbursement of remediation costs under CERCLA or RCRA for remediation at sites we currently own or operate, whether as a result of our or our predecessors' operations, at sites that we previously owned or operated, or at disposal facilities previously used by us, even if such disposal was legal at the time it was undertaken.

Endangered Species. The federal Endangered Species Act, as amended, and comparable state laws, may restrict commercial or other activities that affect endangered and threatened species or their habitats. Some of our current or future planned facilities may be located in areas that are designated as a habitat for endangered or threatened species and, if so, may limit or impose increased costs on facility construction or operation. In addition, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

FERC Regulation

Liquids Pipelines. Certain of our natural gas liquids, petroleum products and crude oil pipeline systems are interstate common carriers subject to regulation by the FERC under the Interstate Commerce Act ("ICA"). These pipelines (referred to as "interstate liquids pipelines") include, but are not limited to, the following principal assets: ATEX, Dixie System, TE Products Pipeline, Front Range Pipeline, Mid-America Pipeline System, Seaway Pipeline, Seminole Pipeline and Texas Express Pipeline.

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The ICA prescribes that the interstate rates we charge for transportation on these interstate liquids pipelines must be just and reasonable, and that the rules applied to our services not unduly discriminate against or confer any undue preference upon any shipper. FERC regulations implementing the ICA further require that interstate liquids pipeline transportation rates and rules be filed with the FERC. The ICA permits interested persons to challenge proposed new or changed rates or rules, and authorizes the FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months. Upon completion of such an investigation, the FERC may require refunds of amounts collected above what it finds to be a just and reasonable level, together with interest. The FERC may also investigate, upon complaint or on its own motion, rates and related rules that are already in effect, and may order a carrier to change them prospectively. Upon an appropriate showing, a shipper may obtain reparations (including interest) for damages sustained for a period of up to two years prior to the filing of its complaint.

The rates charged for our interstate liquids pipeline services are generally based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the year-to-year change in the U.S. Producer Price Index for Finished Goods ("PPI"). A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline's operating costs. During the five-year period commencing July 1, 2011 and ending June 30, 2016, we have been permitted by the FERC to adjust these indexed rate ceilings annually by the PPI plus 2.65%. The FERC is expected to issue an order in 2015 establishing the index for the five-year period commencing July 1, 2016. As an alternative to this indexing methodology, we may also choose to support changes in our rates based on a cost-of-service methodology, by obtaining advance approval to charge "market-based rates," or by charging "settlement rates" agreed to by all affected shippers.

In June 2013, certain parties filed a complaint at the FERC against Enterprise TE Products Pipeline Company LLC ("Enterprise TE") alleging that Enterprise TE's cancellation of certain distillate and jet fuel transportation services violated a provision of a settlement agreement and requested reinstatement of the transportation services and damages. In October 2013, the FERC issued an order holding that Enterprise TE violated the provision in the settlement agreement. While the FERC found that it did not have authority to require Enterprise TE to reinstate the cancelled services, it set the case for an evidentiary hearing to determine if any monetary damages were appropriate. Enterprise TE has subsequently negotiated settlements with all but two of the complainants, and the hearing for the remaining complainants is currently scheduled for August 2015. We are unable to predict the outcome of this proceeding.

The initial rates charged to shippers for crude petroleum transportation services from Cushing, Oklahoma to the Gulf Coast on the Seaway Pipeline are being collected subject to refund and to the outcome of an ongoing FERC rate proceeding. Seaway is charging "committed shipper" rates to shippers who voluntarily agreed under long term contracts to commit to the transportation of, or nevertheless to pay for (to the extent not transported) the transportation of, a minimum volume of crude oil. Seaway is also charging "uncommitted shipper" rates to shippers who have not made any long term contractual commitment to the Seaway Pipeline and instead receive service month-to-month. The committed shipper rates are lower than the uncommitted shipper rates and are an incentive to enter into long term transportation agreements.

In March 2013, the FERC issued a declaratory order stating that the charging by a pipeline of voluntarily agreed-to committed shipper rates is consistent with the FERC's policy of honoring contracts (the "March 2013 Order"). In light of the March 2013 Order, we believe that Seaway's committed shipper rates are not at issue in the ongoing rate proceeding, which began in 2012. However, in September 2013, an administrative law judge ("ALJ") issued an initial decision in the rate proceeding (the "Initial Decision") distinguishing the March 2013 Order and recommending that the FERC find, among other things, that Seaway's committed shipper rates are not just and reasonable and should be re-determined on a cost of service basis along with the uncommitted shipper rates.

In October 2013, Seaway and certain committed rate shippers filed briefs on exceptions objecting to this committed shipper rate aspect of the ALJ's Initial Decision, and also challenging various aspects of the cost of service determinations in the Initial Decision. In February 2014, the FERC issued an order reversing the Initial Decision with respect to the committed rate issue, reiterating its policy of honoring contracts executed between pipelines and committed shippers and remanding the remaining issues to the ALJ for further review. In May 2014, the ALJ issued an initial decision on remand, which largely repeated its prior findings, including as to the committed

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shipper rates. Briefs opposing the initial decision on remand were filed in June 2014. We are unable to predict when the FERC will issue an order or the ultimate outcome of this proceeding.

In February 2014, the FERC upheld an order it issued in May 2012 that denied Seaway's initial application for market-based rate setting authority, without prejudice to Seaway refiling its application based on the guidance provided in the February order. In December 2014, Seaway submitted a new application requesting market-based rate setting authority. In light of the fact-intensive and complex nature of these types of market-based rate applications, we are unable to predict the ultimate outcome on the rates Seaway charges its shippers.

Changes in the FERC's methodologies for approving rates could adversely affect us. In addition, challenges to our regulated rates could be filed with the FERC and future decisions by the FERC regarding our regulated rates could adversely affect our cash flows. We believe the transportation rates currently charged by our interstate liquids pipelines are in accordance with the ICA and applicable FERC regulations. However, we cannot predict the rates we will be allowed to charge in the future for transportation services by such pipelines.

Natural Gas Pipelines and Related Matters. Certain of our intrastate natural gas pipelines, including our Texas Intrastate System and our Acadian Gas System, are subject to regulation by the FERC under the Natural Gas Policy Act of 1978 ("NGPA"), in connection with the transportation and storage services they provide pursuant to Section 311 of the NGPA. Under Section 311 of the NGPA, and the FERC's implementing regulations, an intrastate pipeline may transport gas "on behalf of" an interstate pipeline company or any local distribution company served by an interstate pipeline, without becoming subject to the FERC's broader regulatory authority under Natural Gas Act of 1938 ("NGA"). These services must be provided on an open and nondiscriminatory basis, and the rates charged for these services may not exceed a "fair and equitable" level as determined by the FERC in periodic rate proceedings. Our HIOS pipeline is regulated by the FERC under the NGA. The NGA prescribes that transportation rates charged by pipelines be just and reasonable and that service not be provided on an unduly discriminatory basis. Rates may be lowered on a prospective basis by the FERC if it finds, on its own initiative or as a result of challenges to the rates by shippers, that they are unjust, unreasonable or otherwise unlawful.

We believe that the transportation rates currently charged and the services performed by our natural gas pipelines are all in accordance with the applicable requirements of the NGA, the NGPA, and FERC regulations. However, we cannot predict the rates we will be allowed to charge in the future for transportation services by our pipelines.

The resale of natural gas in interstate commerce is subject to FERC oversight. In order to increase transparency in natural gas markets, the FERC has established rules requiring the annual reporting of data regarding natural gas sales. The FERC has also established regulations that prohibit energy market manipulation. The Federal Trade Commission and the Commodity Futures Trading Commission ("CFTC") have also issued rules and regulations prohibiting energy market manipulation. We believe that our gas sales activities are in compliance with all applicable regulatory requirements.

A violation of the FERC's regulations may subject us to civil penalties, suspension or loss of authorization to perform services or make sales of natural gas, disgorgement of unjust profits or other appropriate non-monetary remedies imposed by the FERC. Pursuant to the Energy Policy Act of 2005, the potential civil and criminal penalties for any violation of the NGA, the NGPA, or any rules, regulations or orders of the FERC, were increased to up to $1 million per day per violation.

State Regulation of Pipeline Transportation Services

Transportation services rendered by our intrastate liquids and natural gas pipelines are subject to regulation in many states, including Alabama, Colorado, Illinois, Kansas, Louisiana, Minnesota, Mississippi, New Mexico, Oklahoma, Texas and Wyoming. The Texas Railroad Commission has the authority to regulate the rates and terms of service for our intrastate natural gas transportation operations in Texas. Although the applicable state statutes and regulations vary widely, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be reasonable and nondiscriminatory. Shippers may challenge tariff rates and practices on our intrastate pipelines.

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Federal Regulation of Marine Operations

The operation of tow boats, barges and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law. These obligations create a variety of risks including, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third party claims and property damages to vessels and facilities.

We are subject to the Jones Act and other federal laws that restrict maritime transportation between U.S. departure and destination points to vessels built and registered in the U.S. and owned and manned by U.S. citizens. As a result of this ownership requirement, we are responsible for monitoring the foreign ownership of our common units and other partnership interests. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels. In addition, the USCG and American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of vessels registered under foreign flags of convenience. Our marine operations are also subject to the Merchant Marine Act of 1936, which under certain conditions would allow the U.S. government to requisition our marine assets in the event of a national emergency.

Climate Change Debate

There is considerable debate over global warming and the environmental effects of greenhouse gas emissions and associated consequences affecting global climate, oceans and ecosystems. As a commercial enterprise, we are not in a position to validate or repudiate the existence of global warming or various aspects of the scientific debate. However, if global warming is occurring, it could have an impact on our operations. For example, our facilities that are located in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels, or disruption of operations from more frequent and severe weather events. Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe. Changes in climate or weather may hinder exploration and production activities or increase the cost of production of oil and gas resources and consequently affect the volume of hydrocarbon products entering our system. Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix. However, we are not in a position to predict the precise effects of global climate change. We are providing this disclosure based on publicly available information on the matter.

In response to scientific studies suggesting that emissions of certain gases, commonly referred to as greenhouse gases, including gases associated with oil and gas production such as carbon dioxide, methane and nitrous oxide among others, may be contributing to a warming of the earth's atmosphere and other adverse environmental effects, various governmental authorities have considered or taken actions to reduce emissions of greenhouse gases. For example, the EPA has taken action under the CAA to regulate greenhouse gas emissions. In addition, certain states, including states in which some of our facilities or operations are located, have taken or proposed measures to reduce emissions of greenhouse gases. Also, the U.S. Congress has proposed legislative measures for imposing restrictions or requiring emissions fees for greenhouse gases. However, there have been no federal regulations enacted to date that specifically restrict greenhouse gas emissions, which has resulted in certain states and regional partnerships taking the initiative. While the state specific efforts seem less burdensome, any such legislation may have the potential to affect our business, customers or the energy sector in general.

On an international level, the U.S. has been involved in negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change ("UNFCCC"). Other nations have already agreed to regulate emissions of greenhouse gases, pursuant to the UNFCCC and a subsidiary agreement known as the Kyoto Protocol, an international treaty pursuant to which participating countries agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. The U.S. is a party to the UNFCCC but did not ratify the Kyoto Protocol. Thus far, negotiations have not resulted in substantive changes that would affect domestic industrial sources of greenhouse gases in the U.S. and it is uncertain whether an international agreement will ever be reached or what the terms of any such agreement would be.

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Following the U.S. Supreme Court's decision in Massachusetts, et al. v. EPA, 549 U.S. 497 (2007), finding that greenhouse gases fall within the CAA definition of "air pollutant," the EPA determined that greenhouse gases from certain sources "endanger" public health or welfare. As a result, the EPA took the position that existing CAA provisions require an assessment of greenhouse gas emissions within the permitting process for certain large new or modified stationary sources under the EPA's Prevention of Significant Deterioration ("PSD") and Title V permit programs beginning in 2011. In 2014, the Supreme Court's decision in Utility Air Regulatory Group v. EPA limited the EPA to include greenhouse gasses in the permitting process only if PSD was already triggered by another listed pollutant. If deemed cost-effective, facilities that trigger permit requirements may be required to reduce greenhouse gas emissions consistent with the "best available control technology" standards. Such changes will also affect state air permitting programs in states that administer the CAA under a delegation of authority, including states in which we have operations. Additionally, in November 2010, the EPA finalized rules expanding its Mandatory Greenhouse Gas Reporting Rule, originally promulgated in October 2009, to be applicable to the oil and natural gas industry. The expansion requires annual, on-site monitoring and additional inventory and reporting of greenhouse gas emissions and affects many of our existing operations and must be considered when planning for future operations. Although subject to legal challenge, the EPA rules promulgated thus far are currently final and effective, and will remain so unless the regulations are overturned by a court ruling, or Congress adopts legislation altering the EPA's regulatory authority.

In January 2015, the White House announced plans to regulate methane emissions attributable to the upstream oil and gas industry, including activities related to gathering and compression, as a greenhouse gas. The EPA has been tasked to publish proposed rules for this matter in 2015, with such rules targeted to go into effect in 2016. Until such proposed rules are developed and published, the impact on our operations is not known; however, it is believed that the only facilities impacted by this proposed rule would be those placed into service after the rules are finalized.

A number of states, individually or in regional cooperation, have also imposed restrictions on greenhouse gas emissions under various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy, or use of fuels with lower carbon content.

These federal, regional and state measures generally apply to industrial sources, including facilities in the oil and gas sector, and could increase the operating and compliance costs of our pipelines, natural gas processing plants, fractionation plants and other facilities. These regulations could also adversely affect market demand or pricing for our products or products served by our midstream infrastructure, by affecting the price of, or reducing the demand for, fossil fuels or providing competitive advantages to competing fuels and energy sources. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final regulations. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage.

Available Information

As a publicly traded partnership, we electronically file certain documents with the Securities and Exchange Commission ("SEC"). We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. Occasionally, we may also file registration statements and related documents in connection with equity or debt offerings. You may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information regarding the Public Reference Room by calling the SEC at (800) SEC-0330. In addition, the SEC maintains a website at www.sec.gov that contains reports and other information regarding registrants that file electronically with the SEC.

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We provide free electronic access to our periodic and current reports on our website, www.enterpriseproducts.com. These reports are available as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC. You may also contact our Investor Relations department at (866) 230-0745 for paper copies of these reports free of charge. The information found on our website is not incorporated into this annual report.

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 transfers naphtha originating in Iraq 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.

Item 1A. Risk Factors.

An investment in our common units or debt securities involves certain risks. If any of the following key risks were to occur, it could have a material adverse effect on our financial position, results of operations and cash flows, as well as our ability to maintain or increase distribution levels. In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment.

Risks Relating to Our Business

Changes in demand for and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.

We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, petrochemical and refined products. As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services. In addition, decreases in demand may be caused by other factors, including

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prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent counterparties do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oil.

In recent years, the prices of crude oil and natural gas have been volatile, and we expect this volatility to continue. During the fourth quarter of 2014, crude oil prices based on WTI dropped sharply to a low of $53.27 per barrel, reflecting a decline from an average of $94.20 per barrel in 2012 and $97.97 per barrel in 2013 and a high of $107.26 per barrel earlier in 2014. WTI crude oil prices averaged $47.33 per barrel in January 2015. The New York Mercantile Exchange ("NYMEX") daily settlement price for natural gas for the prompt month futures contract ranged: in 2012, from a high of $3.90 per MMBtu to a low of $1.91 per MMBtu; in 2013, from a high of $4.46 per MMBtu to a low of $3.11 per MMBtu; and in 2014, from a high of $6.15 per MMBtu to a low of $2.89 per MMBtu.

Generally, prices of hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of other uncontrollable factors, such as: (i) the level of domestic production and consumer product demand; (ii) the availability of imported oil and natural gas and actions taken by foreign oil and natural gas producing nations; (iii) the availability of transportation systems with adequate capacity; (iv) the availability of competitive fuels; (v) fluctuating and seasonal demand for oil, natural gas, NGLs and other hydrocarbon products, including demand for NGL products by the petrochemical, refining and heating industries; (vi) the impact of conservation efforts; (vii) governmental regulation and taxation of production; and (viii) prevailing economic conditions.

We are exposed to natural gas and NGL commodity price risk under certain of our natural gas processing and gathering and NGL fractionation contracts that provide for fees to be calculated based on a regional natural gas or NGL price index or to be paid in-kind by taking title to natural gas or NGLs. A decrease in natural gas and NGL prices can result in lower margins from these contracts, which could have a material adverse effect on our financial position, results of operations and cash flows. Volatility in the prices of natural gas and NGLs can lead to ethane rejection, which results in lower pipeline and fractionation volumes for our assets. Volatility in these commodity prices may also have an impact on many of our customers, which in turn could have a negative impact on their ability to fulfill their obligations to us.

The crude oil, natural gas and NGLs currently transported, gathered or processed at our facilities originate from existing domestic and international resource basins, which naturally deplete over time. To offset this natural decline, our facilities will need access to production from newly discovered properties. Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons. A decrease in exploration and development activities in the regions where our facilities and other energy logistic assets are located could result in a decrease in volumes to our natural gas processing plants, natural gas, crude oil and NGL pipelines, NGL fractionators and offshore platforms, which could have a material adverse effect on our financial position, results of operations and cash flows.

For further discussion regarding these commodity-related risks together with our current commercial outlook for 2015, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations – Commercial and Liquidity Outlook for 2015 – Commercial Outlook for 2015" included under Part II, Item 7 of this annual report.

We face competition from third parties in our midstream energy businesses.

Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted. We compete with other companies, including producers of oil and natural gas, for any such production on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets.

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Our refined products, NGL and marine transportation businesses may compete with other pipelines and marine transportation companies in the areas they serve. We also compete with railroads and third party trucking operations in certain of the areas we serve. Competitive pressures may adversely affect our tariff rates or volumes shipped. Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business.

The crude oil gathering and marketing business can be characterized by thin operating margins and intense competition for supplies of crude oil at the wellhead. A decline in domestic crude oil production could intensify this competition among gatherers and marketers. Our crude oil transportation business competes with common carriers and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies, financial institutions with trading platforms and other companies in the areas where such pipeline systems deliver crude oil.

In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies. Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements. Our key competitors in the gas gathering segment include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to producers we serve, and those producers may also elect to construct proprietary gas gathering systems.

A significant increase in competition in the midstream energy industry could have a material adverse effect on our financial position, results of operations and cash flows.

Our debt level may limit our future financial and operating flexibility.

As of December 31, 2014, we had $18.95 billion in principal amount of consolidated senior long-term debt outstanding, $1.53 billion in principal amount of junior subordinated debt outstanding and $906.5 million in short-term commercial paper notes outstanding. The amount of our future debt could have significant effects on our operations, including, among other things:

§	a substantial portion of our cash flow could be dedicated to the payment of principal and interest on our future debt and may not be available for other purposes, including the payment of distributions on our common units and capital expenditures;

§	credit rating agencies may take a negative view of our consolidated debt level;

§	covenants contained in our existing and future credit and debt agreements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

§	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

§	we may be at a competitive disadvantage relative to similar companies that have less debt; and

§	we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.

Our public debt indentures currently do not limit the amount of future indebtedness that we can incur, assume or guarantee. Although our credit agreements restrict our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial. For information regarding our long-term debt, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our credit agreements and each of the indentures related to our public debt instruments include traditional financial covenants and other restrictions. For example, we are prohibited from making distributions to our partners

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if such distributions would cause an event of default or otherwise violate a covenant under our credit agreements. A breach of any of these restrictions by us could permit our lenders or noteholders, as applicable, to declare all amounts outstanding under these debt agreements to be immediately due and payable and, in the case of our credit agreements, to terminate all commitments to extend further credit.

Our ability to access capital markets to raise capital on favorable terms could be affected by our debt level, when such debt matures, and by prevailing market conditions. Moreover, if the rating agencies were to downgrade our credit ratings, we could experience an increase in our borrowing costs, difficulty assessing capital markets and/or a reduction in the market price of our securities. Such a development could adversely affect our ability to obtain financing for working capital, capital expenditures or acquisitions, or to refinance existing indebtedness. If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term debt obligations or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected levels.

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

Our growth strategy contemplates the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses that enhance our ability to compete effectively and to diversify our asset portfolio, thereby providing us with more stable cash flows. We consider and pursue potential joint ventures, standalone projects and other transactions that we believe may present opportunities to expand our business, increase our market position and realize operational synergies.

We will require substantial new capital to finance the future development and acquisition of assets and businesses. For example, our capital spending for 2014 reflects $6.0 billion of cash payments for capital projects and other investments, including the $2.4 billion paid in connection with Step 1 of the Oiltanking acquisition. Based on information currently available, we expect our total capital spending for 2015 to approximate $3.9 billion, which includes $380 million for sustaining capital expenditures. Any limitations on our access to capital may impair our ability to execute this growth strategy. If our cost of debt or equity capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We also may not be able to raise the necessary funds on satisfactory terms, if at all.

Any future tightening of the credit markets may have a material adverse effect on us by, among other things, decreasing our ability to finance growth capital projects or business acquisitions on favorable terms and by the imposition of increasingly restrictive borrowing covenants. In addition, the distribution yields of any new equity we may issue may be higher than historical levels, making additional equity issuances more expensive.

We also may compete with third parties in the acquisition of energy infrastructure assets that complement our existing asset base. Increased competition for a limited pool of assets could result in our losing to other bidders more often than in the past or acquiring assets at less attractive prices. Either occurrence could limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher cash distributions in the future.

Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

Our growth strategy includes making accretive acquisitions. The success of the Oiltanking acquisition, including the merger that was completed on February 13, 2015, will depend, in part, on our ability to realize the anticipated benefits from combining the businesses of Enterprise and Oiltanking. To realize these anticipated benefits, Enterprise's and Oiltanking's businesses must be successfully combined. If the combined company is not able to achieve these objectives, the anticipated benefits of the merger may not be realized fully or at all or may take

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longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.

Prior to the acquisition, Enterprise and Oiltanking, including their respective subsidiaries, operated independently. It is possible that the integration process could result in the loss of key employees, as well as the disruption of each company's ongoing businesses or inconsistencies in their standards, controls, procedures and policies. Any or all of those occurrences could adversely affect the combined company's ability to maintain relationships with customers and employees after the merger or to achieve the anticipated benefits of the merger. Integration efforts between the two companies will also divert management attention and resources. These integration matters could have an adverse effect on us.

From time to time, we also evaluate and acquire additional assets and businesses that we believe complement our existing operations. We may be unable to successfully integrate and manage the businesses we acquire in the future. We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could have a material adverse effect on our financial position, results of operations and cash flows. Moreover, acquisitions and business expansions involve numerous risks, such as:

§	difficulties in the assimilation of the operations, technologies, services and products of the acquired assets or businesses;

§	establishing the internal controls and procedures we are required to maintain under the Sarbanes-Oxley Act of 2002;

§	managing relationships with new joint venture partners with whom we have not previously partnered;

§	experiencing unforeseen operational interruptions or the loss of key employees, customers or suppliers;

§	inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and

§	diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, amortization and accretion expenses. As a result, our capitalization and results of operations may change significantly following a material acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our financial position, results of operations and cash flows. In addition, any anticipated benefits of a material acquisition, such as expected cost savings or other synergies, may not be fully realized, if at all.

Acquisitions that appear to increase our operating cash flows may nevertheless reduce our operating cash flows on a per unit basis.

Even if we make acquisitions that we believe will increase our operating cash flows, these acquisitions may ultimately result in a reduction of operating cash flow on a per unit basis, such as if our assumptions regarding a newly acquired asset or business did not materialize or unforeseen risks occurred. As a result, an acquisition initially deemed accretive based on information available at the time could turn out not to be. Examples of risks that could cause an acquisition to ultimately not be accretive include our inability to achieve anticipated operating and financial projections or to integrate an acquired business successfully, the assumption of unknown liabilities for which we become liable, and the loss of key employees or key customers. If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will in making such decisions. As a result of the risks noted above, we may not realize the full benefits we expect from a material acquisition, which could have a material adverse effect on our financial position, results of operations and cash flows.

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Our actual construction, development and acquisition costs could materially exceed forecasted amounts.

We have announced and are engaged in multiple significant construction projects involving existing and new assets for which we have expended or will expend significant capital. These projects entail significant logistical, technological and staffing challenges. We may not be able to complete our projects at the costs we estimated at the time of each project's initiation or that we currently estimate. For example, material and labor costs associated with our past projects in the Rocky Mountains region increased over time due to factors such as higher transportation costs and the availability of construction personnel. Similarly, force majeure events such as hurricanes along the U.S. Gulf Coast may cause delays, shortages of skilled labor and additional expenses for these construction and development projects.

If capital expenditures materially exceed expected amounts, then our future cash flows could be reduced, which, in turn, could reduce the amount of cash we expect to have available for distribution. In addition, a material increase in project costs could result in decreased overall profitability of the newly constructed asset once it is placed into commercial service.

Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

One of the ways we intend to grow our business is through the construction of new midstream energy infrastructure assets. The construction of new assets involves numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things, the following:

§	we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits;

§	we will not receive any material increase in operating cash flows until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;

§	we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize;

since we are not engaged in the exploration for and development of natural gas reserves, we may not have access to third party estimates of reserves in an area prior to our constructing facilities in the area. As a result, we may construct facilities in an area where the reserves are materially lower than we anticipate;

§	in those situations where we do rely on third party reserve estimates in making a decision to construct assets, these estimates may prove inaccurate;

§	the completion or success of our construction project may depend on the completion of a third party construction project (e.g., a downstream crude oil refinery expansion) that we do not control and that may be subject to numerous of its own potential risks, delays and complexities; and

§	we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.

A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from expansion opportunities or construction projects, which could impact the level of cash distributions we pay to partners.

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A natural disaster, catastrophe, terrorist or cyber attack or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. We also operate crude oil and natural gas facilities located underwater in the Gulf of Mexico, which can involve complexities, such as extreme water pressure. In addition, our marine transportation business is subject to additional risks, including the possibility of marine accidents and spill events. From time to time, our octane enhancement facility may produce MTBE for export, which could expose us to additional risks from spill events. Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes. The location of our assets and our customers' assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane or tropical storm risk. In addition, terrorists may target our physical facilities and computer hackers may attack our electronic systems.

If one or more facilities or electronic systems that we own or that deliver products to us or that supply our facilities are damaged by severe weather or any other disaster, accident, catastrophe, terrorist or cyber attack or event, our operations could be significantly interrupted. These interruptions could involve significant damage to people, property or the environment, and repairs could take from a week or less for a minor incident to six months or more for a major interruption. Additionally, some of the storage contracts that we are a party to obligate us to indemnify our customers for any damage or injury occurring during the period in which the customers' product is in our possession. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect the market price of our common units.

We believe that EPCO maintains adequate insurance coverage on our behalf, although insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our products. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. For example, we elected to forego windstorm coverage for our Gulf of Mexico offshore assets during the 2014 Atlantic hurricane season, which extends from June 1 through November 30. The combination of increasingly high deductibles and proposed higher premiums resulted in such coverage being uneconomic to us. Although EPCO's coverage does not provide any windstorm coverage for our offshore assets during the annual policy period that began on June 1, 2014, we expect that producers affiliated with our Independence Hub and Marco Polo platforms will continue to provide certain levels of physical damage windstorm coverage for each of these key offshore assets.

In the future, circumstances may arise whereby EPCO may not be able to renew existing insurance policies on our behalf or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

The use of derivative financial instruments could result in material financial losses by us.

Historically, we have sought to limit a portion of the adverse effects resulting from changes in energy commodity prices and interest rates by using derivative instruments. Derivative instruments typically include futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

To the extent that we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, hedging activities can result in losses that might be material to our financial condition, results of operations and cash flows. Such losses could occur under various circumstances, including those situations where a counterparty does not perform its obligations under a hedge arrangement, the hedge is not effective in mitigating the underlying risk,

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or our risk management policies and procedures are not followed. Adverse economic conditions, such as the recent rapid declines in crude oil prices during the fourth quarter of 2014 and beginning of 2015, increase the risk of nonpayment or performance by our hedging counterparties.

See Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for a discussion of our derivative instruments and related hedging activities.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Further, adverse economic conditions increase the risk of nonpayment and nonperformance by customers, particularly customers that are smaller companies. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk.

Our primary market areas are located in the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the U.S. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors.

Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. Our largest non-affiliated customer for 2014 was Shell, which accounted for 8.5% of our consolidated revenues for the year.

See Note 2 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for a discussion of our allowance for doubtful accounts.

Our risk management policies cannot eliminate all commodity price risks. In addition, any non-compliance with our risk management policies could result in significant financial losses.

When engaged in marketing activities, it is our policy to maintain physical commodity positions that are substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the commodity purchased by selling the same commodity for physical delivery to third party users, such as producers, wholesalers, independent refiners, marketing companies or major oil companies. These policies and practices cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when a commodity is purchased against one pricing index and sold against a different index. Moreover, we are exposed to some risks that are not hedged, including price risks on product we own, such as pipeline linefill, which must be maintained in order to facilitate transportation of the commodity on our pipelines. In addition, our marketing operations involve the risk of non-compliance with our risk management policies. We cannot assure you that our processes and procedures will detect and prevent all violations of our risk management policies, particularly if deception or other intentional misconduct is involved. If we were to incur a material loss related to commodity price risks, including non-compliance with our risk management policies, it could have a material adverse effect on our financial position, results of operations and cash flows.

Our variable-rate debt, including those fixed-rate debt obligations that may be converted to variable-rate through the use of interest rate swaps, make us vulnerable to increases in interest rates, which could have a material adverse effect on our financial position, results of operation and cash flows.

At December 31, 2014, we had $20.48 billion in principal amount of consolidated fixed-rate debt outstanding, including current maturities thereof. We also had $906.5 million of commercial paper notes

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outstanding at December 31, 2014. Due to the short term nature of commercial paper notes, we view the interest rates charged in connection with these instruments as variable.

Should interest rates increase significantly, the amount of cash required to service our debt (including any future refinancing of our fixed-rate debt instruments) would increase. Additionally, from time to time, we may enter into interest rate swap arrangements, which could increase our exposure to variable interest rates. As a result, significant increases in interest rates could have a material adverse effect on our financial position, results of operations and cash flows. We had no interest rate swap arrangements in place at December 31, 2014.

An increase in interest rates may also cause a corresponding decline in demand for equity securities in general, and in particular, for yield-based equity securities such as our common units. A reduction in demand for our common units may cause their trading price to decline.

Our pipeline integrity program as well as compliance with pipeline safety laws and regulations may impose significant costs and liabilities on us.

The DOT requires pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in HCAs. The majority of the costs to comply with this integrity management rule are associated with pipeline integrity testing and any repairs found to be necessary as a result of such testing. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

In January 2012, President Obama signed the 2011 Pipeline Safety Act into law. The 2011 Pipeline Safety Act provides, among other things, for additional regulatory oversight of the nation's pipelines, increases the penalties for violations of pipeline safety rules, and complements the DOT's other initiatives. For additional information regarding the pipeline safety regulations and the 2011 Pipeline Safety Act, see "Regulatory Matters—Safety Matters—Pipeline Safety" included under Part I, Item 1 and 2 of this annual report.

If we were to incur material costs in connection with our pipeline integrity program or pipeline safety laws and regulations, those costs could have a material adverse effect on our financial condition, results of operations and cash flows.

Environmental, health and safety costs and liabilities, and changing environmental, health and safety regulation, could have a material adverse effect on our financial position, results of operations and cash flows.

Our operations are subject to various environmental, health and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. Further, we cannot ensure that existing environmental, health and safety regulations will not be revised or that new regulations will not be adopted or become applicable to us. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Certain environmental laws, including CERCLA and analogous state laws and regulations, may impose strict, joint and several liability for costs required to clean-up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.

In addition, future environmental, health and safety law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations. Areas of potential future environmental, health and safety law development include the following items.

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Greenhouse Gases/Climate Change. Responding to scientific reports regarding threats posed by global climate change, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. In addition, some states, including states in which our facilities or operations are located, have individually or in regional cooperation, imposed restrictions on greenhouse gas emissions under various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy sources, or use of replacement fuels with lower carbon content. The adoption and implementation of any federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the crude oil, natural gas or other hydrocarbon products that we transport, store or otherwise handle in connection with our midstream services. The potential increase in our operating costs could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions, and administer and manage a greenhouse gas emissions program. We may not be able to recover such increased costs through customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage. These developments could have a material adverse effect on our financial position, results of operations and cash flows.

Hydraulic Fracturing. Certain of our customers employ hydraulic fracturing techniques to stimulate natural gas and crude oil production from unconventional geological formations (including shale formations), which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. The U.S. federal government, and some states and localities, have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas drilling activities using hydraulic fracturing techniques, including increased litigation. Additional legislation or regulation could also lead to operational delays and/or increased operating costs in the production of oil and natural gas (including natural gas produced from shale plays like the Eagle Ford, Haynesville, Barnett, Marcellus and Utica Shales) incurred by our customers or could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, it may affect the volume of hydrocarbon projects available to our midstream business and have a material adverse effect on our financial position, results of operations and cash flows.

Offshore Drilling. Offshore drilling involves additional risks and different regulations than onshore drilling. Since the Deepwater Horizon (or Macondo) oil spill in the Gulf of Mexico during 2010, an event unrelated to our operations, the U.S. Department of Interior (the "Interior Department") and state regulatory authorities have promulgated substantial additional regulations, including regulations relating to the approval of new permits to drill, the enhanced inspections of oil and gas rigs and more stringent preparedness plans. These new regulatory requirements have added, and may continue to add, delays in the permitting of offshore wells and costs in the planning, permitting, development and operation of new and existing wells by our customers. A decline in, or failure to achieve anticipated volumes of oil and natural gas supplies due to any of these factors could have a material adverse effect on our financial position, results of operations and cash flows.

See "Regulatory Matters" under Part I, Item 1 and 2 of this annual report for more information and specific disclosures relating to environmental, health and safety laws and regulations, and costs and liabilities.

Federal, state or local regulatory measures could have a material adverse effect on our financial position, results of operations and cash flows.

The FERC regulates our interstate liquids pipelines under the ICA and our interstate natural gas pipeline under the NGA. State regulatory agencies regulate our intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines.

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We have ownership interests in natural gas and crude oil pipeline facilities located in the Gulf of Mexico offshore Texas and Louisiana. These facilities are subject to regulation by the FERC and other federal agencies, including the Interior Department, under the Outer Continental Shelf Lands Act and by the DOT's OPS under the NGPSA.

Our intrastate NGL and natural gas pipelines are subject to regulation in many states, including Colorado, Louisiana, New Mexico, Texas and Wyoming. To the extent our intrastate pipelines engage in interstate transportation, they are also subject to regulation by the FERC pursuant to Section 311 of the NGPA. We also have natural gas underground storage facilities in Louisiana and Texas. Although state regulation is typically less comprehensive in scope than regulation by the FERC, our services are typically required to be provided on a nondiscriminatory basis and are also subject to challenge by protest and complaint.

Although our natural gas gathering systems are generally exempt from FERC regulation under the NGA, our natural gas gathering operations could be adversely affected should they become subject to federal regulation of rates and services, or, if the states in which we operate adopt policies imposing more onerous regulation on gas gathering operations. Additional rules and legislation pertaining to these matters are considered and adopted from time to time at both state and federal levels. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

For a general overview of federal, state and local regulation applicable to our assets, see "Regulatory Matters" included within Part I, Item 1 and 2 of this annual report. This regulatory oversight can affect certain aspects of our business and the market for our products and could have a material adverse effect on our financial position, results of operations and cash flows.

The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues.

The FERC, pursuant to the ICA (as amended), the Energy Policy Act and rules and orders promulgated thereunder, regulates the tariff rates for our interstate common carrier liquids pipeline operations. To be lawful under the ICA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with the FERC. In addition, pipelines may not confer any undue preference upon any shipper. Shippers may protest (and the FERC may investigate) the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively. The FERC and interested parties can also challenge tariff rates that have become final and effective. The FERC can also order new rates to take effect prospectively and order reparations for past rates that exceed the just and reasonable level up to two years prior to the date of a complaint. Due to the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate liquids pipelines. The FERC's indexing methodology currently allows a pipeline to increase its rates by a percentage linked to the PPI. As an alternative to this indexing methodology, we may also choose to support our rates based on a cost-of-service methodology, or by obtaining advance approval to charge "market-based rates," or by charging "settlement rates" agreed to by all affected shippers. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs. Changes in the FERC's approved methodology for approving rates, or challenges to our application of that methodology, could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow.

In addition, the FERC, pursuant to the NGA, and rules and regulations promulgated thereunder, regulates the rates for our interstate natural gas pipeline. These rates must be just and reasonable and not unduly discriminatory. Existing pipeline rates may be challenged by customer complaint or by the FERC, and proposed rate increases may be challenged by protest. If the FERC finds the rates are unjust, unreasonable or otherwise unlawful, the FERC may lower them on a prospective basis. Our rates for the interstate natural gas pipeline are derived and charged based on a cost-of-service methodology.

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The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the "Dodd-Frank Act") provides for new statutory and regulatory requirements for swaps and other derivative transactions, including financial and certain physical oil and gas hedging transactions. Under the Dodd-Frank Act, the CFTC has adopted regulations requiring registration of swap dealers and major swap participants, mandatory clearing of swaps, election of the end-user exception for any uncleared swaps by certain qualified companies, recordkeeping and reporting, business conduct standards and position limits among other requirements. Several of these requirements, including position limits rules, allow the CFTC to impose controls that could have an adverse impact on our ability to hedge risks associated with our business and could increase our working capital requirements to conduct these activities.

Based on an assessment of final rules promulgated by the CFTC, we have determined that we are not a swap dealer, major swap participant or a financial entity, and therefore have determined that we qualify as an end-user. The vast majority of our derivative transactions are currently transacted through a Derivatives Clearing Organization, therefore use of the end-user exception will likely not be necessary on a routine basis. We will, however, seek to retain our status as an end-user by taking reasonable measures necessary to avoid becoming a swap dealer, major swap participant or financial entity and other measures to preserve our ability to elect the end-user exception should it become necessary. Derivative transactions that are not clearable and transactions that are clearable but for which we choose to elect the end-user exception are subject to recordkeeping and reporting requirements and potentially additional credit support arrangements including cash margin or collateral. Posting of additional cash margin or collateral could affect our liquidity and reduce our ability to use cash for capital expenditures or other company purposes.

In September 2012, the U.S. District Court for the District of Columbia vacated and remanded the position limits rules adopted by the CFTC based on a necessity finding. In December 2013, the CFTC responded by proposing amended rules in an effort to better conform to the Dodd-Frank Act. Under the proposed rules, the CFTC would place volumetric limitations on transactions in core referenced futures contracts including NYMEX Henry Hub Natural Gas, Light Sweet Crude Oil, New York Harbor Gasoline Blendstock and New York Harbor Heating Oil along with any contracts which are directly or indirectly linked to the price of a core referenced futures contract. These limits include spot month limits leading up to the close of trading for a particular contract and non-spot month limits which would cover all months combined including the spot month. In the proposed rule, the CFTC has provided certain provisions governing Bona Fide Hedges which would enable the exclusion of certain contracts from the calculation of our positions against a given limit. While we believe that the majority of our hedging transactions would meet one or more of the enumerated categories for Bona Fide Hedges, the rules could have an adverse impact on our ability to hedge certain risks associated with our business and could potentially affect our profitability. In 2014, the CFTC reopened the period for public comment on the newly proposed rules, with the most recent comment period closing on January 22, 2015. As of the filing of this annual report, the CFTC has yet to provide final rules.

Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO.

On a standalone basis, Enterprise Products Partners L.P. is a holding company with no business operations and conducts all of its business through its wholly owned subsidiary, EPO. As a result, we depend upon the earnings and cash flows of EPO and its subsidiaries and joint ventures, and the distribution of their cash flows to us in order to meet our obligations and to allow us to make cash distributions to our limited partners.

The amount of cash EPO and its subsidiaries and joint ventures can distribute to us depends primarily on cash flows generated from their operations. These operating cash flows fluctuate based on, among other things, the:

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(i) volume of hydrocarbon products transported on their gathering and transmission pipelines; (ii) throughput volumes in their processing and treating operations; (iii) fees charged and the margins realized for their various storage, terminaling, processing and transportation services; (iv) price of natural gas, crude oil and NGLs; (v) relationships among natural gas, crude oil and NGL prices, including differentials between regional markets; (vi) fluctuations in their working capital needs; (vii) level of their operating costs; (viii) prevailing economic conditions; and (ix) level of competition encountered by their businesses. In addition, the actual amount of cash EPO and its subsidiaries and joint ventures will have available for distribution will depend on factors such as: (i) the level of sustaining capital expenditures incurred; (ii) their cash outlays for expansion (or growth) capital projects and acquisitions; and (iii) their debt service requirements and restrictions included in the provisions of existing and future indebtedness, organizational documents, applicable state business organization laws and other applicable laws and regulations. Because of these factors, we may not have sufficient available cash each quarter to continue paying distributions at our current levels.

Furthermore, the amount of cash we have available for distribution is not solely a function of profitability, which will be affected by non-cash items such as depreciation, amortization and provisions for asset impairments. Our cash flows are also impacted by borrowings under credit agreements and similar arrangements. As a result, we may be able to make cash distributions during periods when we record losses and may not be able to make cash distributions during periods when we record net income. An inability on our part to pay cash distributions to partners at our current levels or projected levels could have an adverse effect on our financial position, results of operations and cash flows.

Risks Relating to Our Partnership Structure

We may issue additional securities without the approval of our common unitholders.

At any time, we may issue an unlimited number of limited partner interests of any type (to parties other than our affiliates) without the approval of our unitholders. Our partnership agreement does not give our common unitholders the right to approve the issuance of equity securities, including equity securities ranking senior to our common units. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: (i) the ownership interest of a unitholder immediately prior to the issuance will decrease; (ii) the amount of cash available for distribution on each common unit may decrease; (iii) the ratio of taxable income to distributions may increase; (iv) the relative voting strength of each previously outstanding common unit may be diminished; and (v) the market price of our common units may decline.

We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses.

Because cash distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance and capital needs. We cannot guarantee that we will continue to pay distributions at the current level each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our general partner. These factors include, but are not limited to: (i) the volume of the products that we handle and the prices we receive for our services; (ii) the level of our operating costs; (iii) the level of competition in our business; (iv) prevailing economic conditions, including the price of and demand for oil, natural gas and other products we transport, store and market; (v) the level of capital expenditures we make; (vi) the amount and cost of capital we can raise compared to the amount of our capital expenditures and debt service requirements; (vii) restrictions contained in our debt agreements; (viii) fluctuations in our working capital needs; (ix) weather volatility; (x) cash outlays for acquisitions, if any; and (xi) the amount, if any, of cash reserves required by our general partner in its sole discretion.

Furthermore, the amount of cash that we have available for distribution is not solely a function of profitability, which will be affected by non-cash items such as depreciation, amortization and provisions for asset impairments. Our cash flows are also impacted by borrowings under credit agreements and similar arrangements. As a result, we may be able to make cash distributions during periods when we record losses and may not be able to make cash distributions during periods when we record net income. An inability on our part to pay cash

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distributions to partners could have a material adverse effect on our financial position, results of operations and cash flows.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.

Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.

The directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to its members. At the same time, our general partner has duties to manage our partnership in a manner that is beneficial to us. Therefore, our general partner's duties to us may conflict with the duties of its officers and directors to its members. Such conflicts may include, among others, the following:

§	neither our partnership agreement nor any other agreement requires our general partner or EPCO to pursue a business strategy that favors us;

decisions of our general partner regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units, and the establishment of additional reserves in any quarter may affect the level of cash available to pay quarterly distributions to our unitholders;

§	under our partnership agreement, our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

our general partner is allowed to resolve any conflicts of interest involving us and our general partner and its affiliates, and may take into account the interests of parties other than us, such as EPCO, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

§	any resolution of a conflict of interest by our general partner not made in bad faith and that is fair and reasonable to us is binding on the partners and is not a breach of our partnership agreement;

§	affiliates of our general partner may compete with us in certain circumstances;

our general partner has limited its liability and reduced its fiduciary duties and has also restricted the remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing our units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

§	we do not have any employees and we rely solely on employees of EPCO and its affiliates;

§	in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions;

§	our general partner may cause us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

§	our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us;

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§	our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

§	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

We have significant business relationships with entities controlled by EPCO and Dan Duncan LLC. For information regarding these relationships and related party transactions with EPCO and its affiliates, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Additional information regarding our relationship with EPCO and its affiliates can be found under Part III, Item 13 of this annual report.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis. The owners of our general partner choose the directors of our general partner.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove our general partner or its officers or directors. Our general partner may not be removed except upon the vote of the holders of at least 60% of our outstanding units voting together as a single class. Since affiliates of our general partner currently own approximately 35.3% of our outstanding common units, the removal of Enterprise GP as our general partner is highly unlikely without the consent of both our general partner and its affiliates. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders' voting rights are further restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price.

Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own 85% or more of the common units then outstanding, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then current market price. As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. They may also incur a tax liability upon the sale of their common units.

Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under our partnership agreement constituted participation in the "control" of our business. Under Delaware

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law, our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner.

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state's partnership statute; or (ii) your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted "control" of our business.

Unitholders may have liability to repay distributions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our general partner's interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner, in accordance with our partnership agreement, may transfer its general partner interest without the consent of unitholders. In addition, our general partner may transfer its general partner interest to a third party in a merger or consolidation or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the sole member of our general partner, currently Dan Duncan LLC, to transfer its equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the Board of Directors and officers of our general partner with their own choices and to influence the decisions taken by the Board of Directors and officers of our general partner.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then cash available for distribution to our unitholders would be substantially reduced.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to a material amount of federal taxation as an entity. The anticipated after-tax economic benefit of an investment in our common units depends, to an extent, on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service ("IRS") on this matter.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate (the highest tax bracket of which is currently at a maximum of 35%) and we would also likely pay additional state income taxes at varying rates. Distributions to our unitholders would

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generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to enhance state-tax collections. If any additional state were to impose an entity-level tax upon us or our operating subsidiaries, the cash available for distribution to our unitholders would be reduced.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, the Obama Administration and members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect the tax treatment of certain publicly traded partnerships. One such Obama Administration budget proposal for fiscal year 2016 would, if enacted, tax publicly traded partnerships with "fossil fuels" activities as corporations for U.S. federal income tax purposes beginning in 2021. Any modification to federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes (i.e., not taxable as a corporation). In addition, such changes may affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income, or otherwise adversely affect an investment in our common units. We are unable to predict whether any of these changes or any other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units and the amount of cash available for distribution to our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

We prorate items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing or proposed Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may adversely impact the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders.

Even if our common unitholders do not receive any cash distributions from us, they will be required to pay taxes on their share of our taxable income.

Because our unitholders will be treated as partners to whom we will allocate taxable income (which could be different in amount from the cash that we distribute), our unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive

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any cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income.

Tax gains or losses on the disposition of our common units could be different than expected.

If a common unitholder sells common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized in the sale and the unitholder's tax basis in those common units. Because distributions in excess of a unitholder's allocable share of our net taxable income decrease the unitholder's tax basis in the unitholder's common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder's tax basis in those common units, even if the price received is less than the unitholder's original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to a unitholder. In addition, because the amount realized may include a unitholder's share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investments in our common units by tax-exempt entities, such as individual retirement accounts ("IRAs"), other retirement plans and non-U.S. persons, raise issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder's tax returns.

Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property even if the unitholder does not live in any of those jurisdictions. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, they may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is the responsibility of each unitholder to file its own federal, state and local tax returns.

The sale or exchange of 50% or more of the total interests in our capital and profits within any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our existing partnership and having formed a new partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which could result in us filing two tax returns (and

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our unitholders could receive two Schedules K-1 if certain relief were unavailable) for one fiscal year and could result in the deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a common unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

Item 1B. Unresolved SEC Staff Comments.

None.

Item 3. 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. Except as set forth below, we are not aware of any material pending legal proceedings at March 2, 2015 to which we are a party, other than routine litigation incidental to our business.

ETP Matter

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

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

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us against ETP and (iii) prejudgment interest in the amount of $66.4 million. The court also awarded post-judgment interest on such aggregate amount, to accrue at a rate of 5%, compounded annually.

We do not believe that the verdict or the judgment entered against us is supported by the evidence or the law and intend to vigorously oppose the judgment through the appeals process.

Environmental Matters

On occasion, we are assessed monetary sanctions by governmental authorities related to administrative or judicial proceedings involving environmental matters. The following information summarizes such matters where the amount of monetary sanctions sought is at least $0.1 million. We do not believe that any expenditure related to the following matters will be material to our consolidated financial statements.

The Texas Commission on Environmental Quality notified us in the fourth quarter of 2012 that several, existing notices of enforcement issued in connection with air emissions by our Houston-area operations would be combined into one order. We believe that the eventual resolution of this consolidated order will result in monetary sanctions in excess of $0.4 million.

In July 2013, the U.S. Environmental Protection Agency issued a Consent Agreement and Final Order in connection with certain risk management policies at our Mont Belvieu, Texas complex. We believe that the eventual resolution of these matters will result in monetary sanctions of approximately $0.4 million.

§	In January 2014, we paid the State of Texas, acting through the District Attorney's Office in Travis County, Texas, a $1.2 million fine related to environmental compliance and recordkeeping matters at a tractor-trailer repair and washing facility located in Brazoria County, Texas.

In August 2014, following a Notice of Violation sent to us in the third quarter of 2013, we received information from the New Mexico Oil Conservation Division that they expect to assess us a penalty in connection with violations involving a hydrostatic test permit for a pipeline project in Santa Fe County, New Mexico. The eventual resolution of these matters may result in monetary sanctions in excess of $0.1 million.

In January 2015, the Attorney General of Texas filed litigation against us for Clean Air Act violations resulting from the February 2011 NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility. The eventual resolution of these matters may result in monetary sanctions in excess of $0.1 million.

For more information regarding our litigation matters, see "Litigation" under Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report, which subsection is incorporated by reference into this Item 3.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant's Common Equity, Related Unitholder Matters

and Issuer Purchases of Equity Securities.

Our common units are listed on the NYSE under the ticker symbol "EPD." As of January 31, 2015, there were approximately 3,000 unitholders of record of our common units. The following table presents high and low sales prices for our common units for the periods presented (as reported by the NYSE Composite ticker tape) and the amount, record date and payment date of the quarterly cash distributions we paid on each of our common units with respect to such periods.

					Cash Distribution History
	Price Ranges				Per		Record	Payment
	High		Low		Unit		Date	Date
2012
1st Quarter	$	26.48	$	22.89	$	0.3138	04/30/12	05/09/12
2nd Quarter	$	26.47	$	22.84	$	0.3175	07/31/12	08/08/12
3rd Quarter	$	27.49	$	25.39	$	0.3250	10/31/12	11/08/12
4th Quarter	$	27.69	$	24.26	$	0.3300	01/31/13	02/07/13
2013
1st Quarter	$	30.17	$	25.51	$	0.3350	04/30/13	05/07/13
2nd Quarter	$	31.78	$	28.06	$	0.3400	07/31/13	08/07/13
3rd Quarter	$	32.80	$	28.83	$	0.3450	10/31/13	11/07/13
4th Quarter	$	33.46	$	29.57	$	0.3500	01/31/14	02/07/14
2014
1st Quarter	$	35.50	$	31.51	$	0.3550	04/30/14	05/07/14
2nd Quarter	$	39.26	$	34.52	$	0.3600	07/31/14	08/07/14
3rd Quarter	$	41.38	$	35.55	$	0.3650	10/31/14	11/07/14
4th Quarter	$	40.95	$	30.71	$	0.3700	01/30/15	02/06/15

Actual cash distributions are paid by us within 45 days after the end of each fiscal quarter. We expect that our cash distributions will be funded primarily through cash provided by operating activities. Although the payment of cash distributions is not guaranteed, we believe that our operations will continue to generate cash sufficient to pay distributions in the foreseeable future at levels comparable to those presented in the preceding table.

For additional information regarding our cash distributions to partners, see Note 13 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Recent Issuance of Unregistered Securities

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

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Common Units Authorized for Issuance Under Equity Compensation Plan

See "Securities Authorized for Issuance Under Equity Compensation Plans" included under Part III, Item 12 of this annual report, which is incorporated by reference into this Item 5.

Issuer Purchases of Equity Securities

A total of 2,634,074 unit-based awards (e.g., restricted common unit awards granted to key employees of EPCO) vested and were converted to common units during 2014. Of this amount, 894,383 were sold back to us by employees to meet their related tax withholding requirements. The total cost of these repurchased units was $30.2 million. We cancelled such treasury units immediately upon acquisition.

The following table summarizes our repurchase activity during 2014 in connection with these vesting transactions:

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 2014 (1)		842,782	$	32.85		--		--
May 2014 (2)		26,386	$	36.62		--		--
August 2014 (3)		8,849	$	37.52		--		--
November 2014 (4)		16,366	$	36.91		--		--
(1) Of the 2,479,724 restricted common units that vested in February 2014 and converted to common units, 842,782 units were sold back to us by employees to cover related withholding tax requirements.
(2) Of the 73,800 restricted common units that vested in May 2014 and converted to common units, 26,386 units were sold back to us by employees to cover related withholding tax requirements.
(3) Of the 32,874 restricted common units that vested in August 2014 and converted to common units, 8,849 units were sold back to us by employees to cover related withholding tax requirements.
(4) Of the 47,676 restricted common units that vested in November 2014 and converted to common units, 16,366 units were sold back to us by employees to cover related withholding tax requirements.

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

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Item 6. Selected Financial Data.

The following table presents selected historical consolidated financial data of our partnership. This information has been derived from and should be read in conjunction with our audited financial statements included under Part II, Item 8 of this annual report, which presents our audited balance sheets as of December 31, 2014 and 2013 and related statements of consolidated operations, comprehensive income, cash flow and equity for the three years ended December 31, 2014, 2013 and 2012, respectively. As presented in the table, amounts are in millions (except dollar per unit data).

	For the Year Ended December 31,
	2014		2013		2012		2011		2010
Statements of operations data:
Total revenues	$	47,951.2	$	47,727.0	$	42,583.1	$	44,313.0	$	33,739.3
Total costs and expenses	$	44,435.0	$	44,427.0	$	39,538.2	$	41,500.3	$	31,654.1
Equity in income of unconsolidated affiliates	$	259.5	$	167.3	$	64.3	$	46.4	$	62.0
Operating income	$	3,775.7	$	3,467.3	$	3,109.2	$	2,859.1	$	2,147.2
Net income	$	2,833.5	$	2,607.1	$	2,428.0	$	2,088.3	$	1,383.7
Net income attributable to noncontrolling interests	$	46.1	$	10.2	$	8.1	$	41.4	$	1,062.9
Net income attributable to limited partners	$	2,787.4	$	2,596.9	$	2,419.9	$	2,046.9	$	320.8
Earnings per unit:
Basic ($/unit)	$	1.51	$	1.45	$	1.40	$	1.24	$	0.58
Diluted ($/unit)	$	1.47	$	1.41	$	1.35	$	1.19	$	0.58
Cash distributions paid with respect to period ($/unit)	$	1.4500	$	1.3700	$	1.2863	$	1.2176	$	1.1350

	As of December 31,
	2014		2013		2012		2011		2010
Balance sheet data:
Property, plant and equipment, net	$	29,881.6	$	26,946.6	$	24,846.4	$	22,191.6	$	19,332.9
Investments in unconsolidated affiliates	$	3,042.0	$	2,437.1	$	1,394.6	$	1,859.6	$	2,293.1
Total assets	$	47,100.7	$	40,138.7	$	35,934.4	$	34,125.1	$	31,360.8
Long-term debt, including current maturities thereof	$	21,363.8	$	17,351.5	$	16,201.8	$	14,529.4	$	13,563.5
Total liabilities	$	27,408.5	$	24,698.3	$	22,638.4	$	21,905.8	$	19,460.0
Equity:
Partners equity	$	18,063.2	$	15,214.8	$	13,187.7	$	12,113.4	$	11,374.2
Noncontrolling interests		1,629.0		225.6		108.3		105.9		526.6
Total equity	$	19,692.2	$	15,440.4	$	13,296.0	$	12,219.3	$	11,900.8
Limited partner units outstanding (millions)		1,937.3		1,871.4		1,797.6		1,763.2		1,687.4

General Discussion of Our Selected Financial Data Since 2010

In general, our results of operations increased from 2010 through 2014 primarily due to increased demand for our products and services, particularly in response to increased hydrocarbon production from supply basins such as the Eagle Ford Shale in South Texas, Permian Basin in West Texas and the Rocky Mountains region. The increase in demand supported our long-term capital spending program. As these projects are completed and commence operations, they contribute additional sources of cash flow to our operating results.

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. A decrease in our consolidated marketing revenues due to lower energy commodity sales prices may not result in a decrease in operating income 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.

Our property, plant and equipment balances have increased since 2010 as a result of our capital spending program. For information regarding our capital spending, see "Capital Spending" included under Part II, Item 7 of this annual report.

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Investments in unconsolidated affiliates decreased in 2011 and 2012 primarily due to the liquidation of our investment in Energy Transfer Equity, L.P. ("Energy Transfer Equity"). In general, investments in unconsolidated affiliates have increased since 2012 as a result of cash contributions we made to investees to fund their major capital projects (e.g., Texas Express Pipeline, Front Range Pipeline and the Seaway Pipeline).

Our debt balances have increased since 2010 primarily due to the funding of a portion of our capital spending program using borrowings under bank credit agreements and the issuance of senior notes. Apart from the impact of merger-related changes (such as those described in the following section), our equity balances have also increased over this period due to the funding of our capital spending program using net proceeds from the issuance of common units in connection with underwritten offerings, our distribution reinvestment plan and employee unit purchase plan programs and "at-the-market" program. Additional information regarding our results of operations, liquidity and capital resources and capital spending can be found under Part II, Item 7 of this annual report.

Impact of Holdings Merger on 2010 Selected Financial Data

On September 3, 2010, Enterprise GP Holdings L.P. ("Holdings"), Enterprise, Enterprise GP, Enterprise Products GP, LLC ("EPGP," the former general partner of Enterprise) and Enterprise ETE LLC ("Holdings MergerCo," a wholly owned subsidiary of Enterprise) entered into a merger agreement (the "Holdings Merger Agreement"). On November 22, 2010, the Holdings Merger Agreement was approved by the unitholders of Holdings and the merger of Holdings with and into Holdings MergerCo and related transactions were completed, with Holdings MergerCo surviving such merger. Collectively, we refer to these transactions as the "Holdings Merger." As a result of completing the Holdings Merger, Enterprise GP, which had previously been the general partner of Holdings ("Holdings GP"), became Enterprise's general partner.

Prior to the merger (the "Holdings Merger"), Enterprise was a consolidated subsidiary of Holdings, which was Enterprise's parent. Upon completion of the Holdings Merger, Holdings merged with and into a wholly owned subsidiary of Enterprise. The Holdings Merger resulted in Holdings being considered the surviving consolidated entity for accounting purposes, while Enterprise was the surviving consolidated entity for legal purposes. From an accounting perspective, Holdings was deemed the acquirer of the noncontrolling interests in Enterprise that were previously recognized in Holdings' consolidated financial statements (i.e., the acquisition of Enterprise's common units and other limited partner interests that were owned by parties other than Holdings). As a result of the Holdings Merger, Enterprise's consolidated financial and operating results prior to November 22, 2010 were presented as if Enterprise was Holdings from an accounting perspective (i.e., the consolidated financial statements of Holdings became the historical financial statements of Enterprise).

At the effective time of the Holdings Merger, each issued and outstanding unit representing limited partner interests in Holdings was cancelled and converted into the right to receive Enterprise common units based on the 1.5 to 1 exchange ratio. We issued an aggregate 417,626,908 of our common units (net of fractional common units cashed out) as consideration in the Holdings Merger and, immediately after the merger, cancelled 43,126,354 of our common units previously owned by Holdings. Limited partner units outstanding at December 31, 2010 and each subsequent period include both the common units issued to third parties and affiliates since our initial public offering in 1998 and those issued in connection with the Holdings Merger.

Since Holdings regarded third party and affiliate ownership of our common units and other limited partner units as noncontrolling interests prior to the Holdings Merger, net income attributable to limited partners for 2010 is significantly different than the amounts following the Holdings Merger. Net income attributable to limited partners following the Holdings Merger reflects all of our limited partners. Also, basic and diluted earnings per unit data for period prior to the Holdings Merger reflect those reported by Holdings, after retroactively adjusting the amounts to reflect the 1.5 to one unit-for-unit exchange ratio.

Cash distributions per unit presented for 2010 represent the sum of cash distributions declared and paid by Holdings with respect to the first, second and third quarters of 2010 and the cash distribution declared and paid by Enterprise with respect to the fourth quarter of 2010. Cash distributions per unit for 2014, 2013, 2012 and 2011 represent those declared and paid by us with respect to those years.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

For the Years Ended December 31, 2014, 2013 and 2012

The following information should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report. Our financial statements have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States.

Key References Used in this Management's Discussion and Analysis

In addition to owning our general partner, EPCO and its privately held affiliates owned approximately 35.3% of our limited partner interests at December 31, 2014.

As generally used in the energy industry and in this annual 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

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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 annual report speak only as of the 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

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 51,300 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 October 1, 2014, we announced our acquisition of the general partner and certain limited partner interests of Oiltanking Partners, L.P. ("Oiltanking"). See "Significant Recent Developments" within this Part II, Item 7 for information regarding this business combination.

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.

Significant Recent Developments

Acquisition of Oiltanking Partners, L.P.

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

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

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with an exercise of the option due to a Trigger Event will be solely cash, determined in the same manner as the price otherwise payable upon the exercise of the Liquidity Option in the absence of a Trigger Event.

As a result of our acquisition of Oiltanking GP, we began consolidating the financial statements of Oiltanking and its general partner on October 1, 2014. This business combination was accounted for using the acquisition method of accounting. This method requires us to allocate the cost of a business combination to the assets acquired and liabilities assumed based on their estimated fair values on the transaction date. For information regarding our accounting for this business combination, see Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Expansion of Eagle Ford Crude Oil Pipeline System

In November 2014, we, along with Plains All American Pipeline, L.P. ("Plains") announced an expansion of our Eagle Ford Crude Oil Pipeline System in South Texas. The expansion project entails the construction of a new 55-mile crude oil gathering system that will connect Karnes County and Live Oak County production areas in Texas to the joint venture's Three Rivers, Texas terminal. The joint venture will also construct an additional 70-mile, 20-inch pipeline from Three Rivers to Corpus Christi, Texas as well as expand storage and pumping capacity at Three Rivers. When combined with the expansion project announced in September 2013, this project effectively loops the Eagle Ford Crude Oil Pipeline System from Gardendale, Texas to Corpus Christi and increases the system's capacity to transport light and medium grades of crude oil to over 600 MBPD. These expansions are supported by a long-term production commitment and are expected to be placed into service in the third quarter of 2015.

Plains and Enterprise will also construct a new deep water terminal on the Corpus Christi ship channel to support the expected increase in crude oil volumes to be shipped via pipeline to the region. The dock is being designed to handle a variety of ocean-going vessels and is planned to be in service by 2017.

Plans to Construct Additional Midstream Infrastructure to Serve the Delaware Basin

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connections at our Hobbs facility, shippers will have access to our NGL fractionation and storage complex in Mont Belvieu, Texas. Additionally, we plan to deliver residue gas from the South Eddy plant through new interconnections with existing third party pipelines.

Initial Stage of Aegis Ethane Pipeline Completed

In September 2014, we announced that the first segment, or 60 miles, of our Aegis Ethane Pipeline was complete and ready to commence ethane deliveries between our Mont Belvieu storage complex and Beaumont, Texas. The 270-mile Aegis Ethane Pipeline (or "Aegis") represents a key component of our planned ethane header system stretching from Corpus Christi, Texas to the Mississippi River in Louisiana. After taking into account existing South Texas midstream infrastructure and completion of the first segment of Aegis, this 500-mile ethane header system is now in service from Corpus Christi to Beaumont. The remainder of Aegis will be completed in two phases. The next segment between Beaumont and Lake Charles, Louisiana is expected to be completed in the third quarter of 2015. The final segment from Lake Charles to the Mississippi River is expected to be completed by the end of 2015.

Plans to Build Ninth NGL Fractionator at Our Mont Belvieu, Texas Complex

SEKCO Oil Pipeline Completed

The SEKCO Oil Pipeline was completed in July 2014, with crude oil shipments starting in January 2015 when the Lucius oil and gas field commenced operations. The SEKCO Oil Pipeline is owned by Southeast Keathley Canyon Pipeline Company, L.L.C., which is owned 50% by us and 50% by Genesis Energy, L.P. The SEKCO Oil Pipeline is a 149-mile crude oil gathering pipeline serving producers in the Lucius oil and gas field located in the southern Keathley Canyon area of the deepwater central Gulf of Mexico. The new pipeline connects the third party-owned Lucius-truss spar floating production platform to an existing junction platform at South Marsh Island 205, which is part of our Poseidon Oil Pipeline System. We serve as operator of the SEKCO Oil Pipeline, which has a capacity of 115 MBPD.

Seaway Crude Oil Pipeline Loop Completed

In June 2014, Seaway Crude Pipeline Company LLC ("Seaway") completed a pipeline looping project involving its Longhaul System. This expansion project included the construction of an additional 512-mile, 30-inch pipeline that transports crude oil south from the Cushing hub to Seaway's Jones Creek terminal. With the looping project complete, the aggregate transportation capacity of the Longhaul System is approximately 850 MBPD, depending on the type and mix of crude oil being transported and other variables. Crude oil deliveries using the new pipeline (referred to as the "Seaway Pipeline looping project") commenced in December 2014.

Seaway's Jones Creek terminal is connected to our ECHO crude oil storage facility located in Houston, Texas by a 65-mile, 36-inch pipeline. Construction of a 100-mile, 30-inch pipeline from ECHO to Beaumont/Port Arthur, Texas, was also completed in July 2014. These new pipeline construction projects complement ongoing expansion activities at ECHO, which include the completion of three new storage tanks during the second quarter of 2014.

Marine Terminal Begins Exporting Refined Products

In May 2014, we began loading cargoes of refined products for export on our reactivated marine terminal in Beaumont, Texas, and within six months the facility was sold out. Located on the Neches River, the terminal can load at rates up to 15,000 barrels per hour. The facility includes a dock with a 40-foot draft that can accommodate Panamax size vessels that have a capacity of up to 400,000 barrels. The terminal has access to more than 12.0 MMBbls of refined products storage and receives products from eight refineries, representing approximately 3.3

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MMBPD of capacity, as well as the Colonial Pipeline.

The costs for improvements and modifications required to resume operations at the terminal, which included channel dredging, new pipeline construction, and the installation of new loading arms and vapor recovery systems, are supported by long-term customer commitments. Ongoing expansion of the Beaumont refined products terminal, also supported by long-term customer commitments, includes significant additional on-site storage and ancillary equipment for gasoline blending operations. With its strategic location and enhanced capabilities, the Beaumont marine terminal provides optionality for customers, allowing them to capture added value from the evolving fundamentals of the domestic and international refined products markets.

Plans to Construct Ethane Export Facility on Houston Ship Channel

In April 2014, we announced plans to construct a fully refrigerated ethane export facility on the U.S. Gulf Coast. The new facility, which is located on the Houston Ship Channel, is expected to have an aggregate loading rate of approximately 10,000 barrels per hour and is supported by long-term contracts. We expect the ethane export facility to begin operations in the third quarter of 2016.

Our ethane export facility will provide new markets for domestically-produced ethane, and will assist U.S. producers in increasing their associated production of natural gas and crude oil. We estimate that U.S. ethane production capacity currently exceeds U.S. demand by 300 MBPD and could exceed demand by up to 700 MBPD by 2020, after considering the estimated incremental demand from new ethylene facilities that have been announced.

The ethane export facility will be integrated with our Mont Belvieu complex. Our Mont Belvieu complex receives NGL supplies from several major producing basins across the U.S., including the Marcellus and Utica Shales via our recently completed Appalachia-to-Texas Express ("ATEX") ethane pipeline. We believe that our integrated NGL system offers supply assurance and diversification for the ethane export facility.

Front Range Pipeline Begins Operations

Our Front Range Pipeline commenced operations in February 2014. This 435-mile pipeline transports NGLs originating from the Denver-Julesburg production basin in Weld County, Colorado to Skellytown, Texas in Carson County. With connections to our Mid-America Pipeline System and Texas Express Pipeline, the Front Range Pipeline provides producers in the Denver-Julesburg basin with access to the Gulf Coast, which is the largest NGL market in the U.S. Initial throughput capacity for the Front Range Pipeline is 150 MBPD, which could be expanded to approximately 230 MBPD with certain system modifications. The Front Range Pipeline is owned by Front Range Pipeline LLC, which is a joint venture among us and affiliates of DCP Midstream Partners LP and Anadarko Petroleum Corporation. We operate the Front Range Pipeline and own a one-third member interest in Front Range Pipeline LLC.

ATEX Pipeline Begins Operations

Our ATEX pipeline, which commenced operations in January 2014, transports ethane primarily southbound from NGL fractionation plants located in Pennsylvania, West Virginia and Ohio to our Mont Belvieu storage complex. The ethane extracted by these fractionation facilities originates from the Marcellus and Utica Shale production areas. In addition to newly constructed pipeline segments, significant portions of the ATEX pipeline consist of segments that were formerly used in refined products transportation service by our TE Products Pipeline. Initial throughput capacity for the ATEX pipeline is 125 MBPD, which could be expanded to approximately 265 MBPD with certain system modifications.

ATEX terminates at our Mont Belvieu storage facility, which includes an extensive pipeline distribution system. With the addition of our Aegis Ethane Pipeline, we will, through our Mont Belvieu facilities, link Marcellus and Utica Shale-produced ethane to existing ethylene production facilities along the U.S. Gulf Coast and provide supply security to support construction of new third party ethylene plants currently planned in Texas and Louisiana.

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Expansion of Houston Ship Channel LPG Export Terminal

We provide customers with LPG export services at our marine terminal located on the Houston Ship Channel. This terminal has the capability to load cargoes of fully refrigerated, low-ethane propane and/or butane onto multiple tanker vessels simultaneously. In March 2013, we completed an expansion project at this terminal that increased its loading capability from 4.0 MMBbls per month to 7.5 MMBbls per month. Our LPG export services continue to benefit from increased NGL supplies produced from domestic shale plays such as the Eagle Ford Shale and strong international demand for propane as a feedstock in ethylene plant operations and for power generation and heating purposes.

In September 2013, we announced an expansion project at this LPG export terminal that is expected to increase its ability to load cargoes from 7.5 MMBbls per month to approximately 9.0 MMBbls per month. This expansion project is expected to be completed in the first quarter of 2015.

In January 2014, we announced a further expansion of this LPG export terminal that is expected to increase its ability to load cargoes from approximately 9.0 MMBbls per month to in excess of 16.0 MMBbls per month. Once this expansion project is completed, we expect our maximum loading capacity at this export terminal will be approximately 27,000 barrels per hour. The expanded LPG export terminal is expected to be in service by the end of 2015 and is supported by long-term LPG export agreements.

Mid-America Pipeline System's Rocky Mountain Expansion Project Begins Operations

In January 2014, we announced the completion of an expansion project involving the Rocky Mountain pipeline of our Mid-America Pipeline System. This expansion project involved looping 265 miles of the Rocky Mountain pipeline, as well as related pump station modifications, which increased transportation capacity on the pipeline from approximately 275 MBPD to 350 MBPD. This expansion project was built to accommodate growing natural gas and NGL production from major supply basins in Colorado, New Mexico, Utah and Wyoming.

Commercial and Liquidity Outlook for 2015

Commercial Outlook for 2015

We provide midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. Factors that can affect the demand for our products and services include domestic and international economic conditions, the market price and demand for energy, the cost to develop natural gas and crude oil reserves in the U.S., state and federal regulation, and the cost and availability of capital to energy companies to invest in upstream exploration and production activities.

As a result of significant advances in non-conventional drilling and production technology, North American reserves and production of hydrocarbons from shale developments have increased substantially. The rapid increase in U.S. hydrocarbon supplies has led to a reduction in imports of crude oil, NGLs, refined products and natural gas into the U.S. Conversely, this trend has also resulted in significant increases in hydrocarbon exports from the U.S., particularly of refined products and LPGs, and contributed to price volatility in the price of natural gas and NGLs, especially of ethane.

In the summer and fall of 2014, oil economists, including those at the International Energy Agency, began to express concerns about a growing global excess of crude oil and refined products in light of a weaker global economic outlook (especially for Europe and China) and in the face of surging supplies from the U.S. as well as production growth from Iraq, Libya, Iran and certain African countries. In the fall of 2014, the market began to see signals of growing crude oil inventories coupled with unusual monthly discounts from OPEC nations to certain markets in order to retain their market share. On November 27, 2014, OPEC met for a regularly scheduled meeting and could not agree to cut their crude oil production in order to stabilize global oil prices. In addition to not cutting production, as part of the November meeting, Saudi Arabia indicated that it believed that market forces, rather than OPEC's self-imposed quotas, should determine global oil prices. As a result of no production cuts from OPEC and the strong communication from Saudi Arabia, oil prices rapidly deteriorated, falling quickly from approximately $75 per barrel to $45 per barrel by the end of January 2015.

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The collapse in crude oil prices is impacting market dynamics for hydrocarbons around the world, resulting in uncertainty in supply and demand fundamentals for crude oil, refined products, NGLs, natural gas and other energy-intensive products including petrochemicals. While it is impossible to predict exactly how lower energy commodity prices will impact us in 2015, we expect that an extended period of significantly lower crude oil and NGL prices will slow drilling activity in the regions we serve, which ultimately could reduce the overall supply of crude oil, natural gas and NGLs available to our facilities. While all domestic production basins are expected to be impacted in 2015, we expect the largest reductions in drilling activity will be in domestic supply basins located farthest from the U.S. Gulf Coast.

Although the exact impact of drilling and well completions is uncertain, we currently believe that producers will remain focused on the Eagle Ford Shale and Permian Basin regions because of their favorable returns on capital and relative close proximity to Gulf Coast markets, which increases their net operating cash flows compared to other more distant producing regions. It is too early to predict how drilling programs in other plays farther from the Gulf Coast will be impacted, but we expect that many basins that have lower returns on capital due to higher transportation costs will likely experience a significant reduction in drilling activity until crude oil, NGL and natural gas prices improve. Many producers have indicated that they expect to negotiate reductions in their drilling and completion costs to help mitigate some of the impact from energy commodity falling prices. Nevertheless, many producers are indicating that they expect their production to continue to increase in 2015 compared to 2014 as they work through significant completion backlogs and drilling/contractual commitments and rely on financial hedges to help support their near-term cash flow needs. Once these backlogs and commitments are satisfied and any financial hedges settle, producers are generally uncertain about their post-2015 drilling and production plans in light of the current commodity price environment.

Lower energy commodity prices for an extended period of time could lead to significant and prolonged reductions in drilling activity that would eventually result in lower production volumes and could negatively impact our gross operating margins relative to natural gas processing, pipeline operations and NGL fractionation, and could also adversely affect regional price spreads that could lower results from our marketing activities. In addition, lower energy commodity prices over an extended period of time could contribute to a decrease in our capital spending for new assets or expansion opportunities for existing assets. Certain producers have already announced significant reductions in their capital budgets and production plans for 2015, and others have said that they are in the process of revising their 2015 capital budgets in light of the decline in crude oil prices. Furthermore, producers that have published capital spending and production estimates for 2015 have, in general, noted that they are subject to change as the current situation develops.

In contrast to the negative impacts on energy producers, lower energy costs could lead to an increase in energy consumption and an increase in investments in energy intensive industries (e.g., steel manufacturing and industrial chemicals) as lower energy costs reduce the variable costs of such industries and improve investment returns of some projects. An increase in demand for crude oil or NGLs from these types of industries, along with other positive consumer-driven demand responses to the lower prices, may help to balance crude oil supply and demand fundamentals by the end of 2015. Regardless of such market dynamics, almost all of the assets we have under construction or have recently completed, whether supply or end-use oriented, are backed by significant long-term fee-based commitments from shippers and/or end-use customers. In addition, many of our recent pipeline projects are backed by contractual volume commitments over the next several years (e.g., shipper commitments on our ATEX, Texas Express and Front Range pipelines), thus providing support to the cash flows generated by these assets. For additional information regarding our recent significant projects, see "Significant Recent Developments" within this Part II, Item 7.

Natural gas has been trading at a significant discount to crude oil for the last several years due to changes in supply and demand fundamentals and, in spite of the recent downturn in crude oil prices, natural gas continues to trade at a significant discount relative to historical norms. For example, on an energy-equivalent basis, natural gas prices for 2015 are forecast to be 30% to 36% of the price of crude oil (based on prices quoted in futures markets in January 2015). For 2014 and 2013, natural gas was priced at 27% and 22% of crude oil on an energy-equivalent basis, respectively. In addition, ethane prices have decreased over time in terms of price per gallon and as a percentage relative to the price of crude oil on an energy-equivalent basis. The decline in ethane prices is attributable to excess domestic supply. For example, the average price of ethane in 2012 was $0.40 per gallon (or 37% of the relative price of crude oil on an energy-equivalent basis). The average price of ethane continued to decline in 2013,

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decreasing to $0.26 per gallon (or 23% of the relative price of crude oil on an energy-equivalent basis) and averaged $0.27 per gallon (or 25% of the relative price of crude oil on an energy-equivalent basis) in 2014. At the end of January 2015, ethane was priced at $0.18 per gallon (or 36% of the relative price of crude oil on an energy-equivalent basis).

As a result of these natural gas and ethane price trends, producers have significantly decreased their drilling activity in onshore areas where natural gas production is considered "dry" or "lean" (i.e., the amount of NGLs produced in connection with the natural gas production is relatively small) and have focused more on NGL-rich natural gas and crude oil developments over the last several years. A similar trend is also occurring in the Gulf of Mexico, with producers investing capital to develop new sources of crude oil production rather than areas where natural gas production is prevalent. In general, the focus on crude oil and NGL-rich supply basins by producers has contributed to significant increases in domestic production of these hydrocarbons. The excess supply and inventories have led to lower prices for these energy commodities and contributed to a global focus on exports of U.S. hydrocarbons, to the extent such exports are permitted by U.S. governmental authorities.

U.S. LPG exports continue to increase as a result of ample supplies, increased export capacity and competitive prices as compared to international markets. Overall, U.S. propane waterborne exports increased from approximately 153 MBPD in 2012 to 288 MBPD in 2013 and to 403 MBPD in 2014. Markets in Central and South America have been the major source of new demand for U.S. LPG exports; however, volumes are also being transported to Northwest Europe and Far East Asia. LPG exports from the U.S. Gulf Coast to Central and South America are expected to increase in the future. Similarly, greater volumes of Gulf Coast-sourced LPGs are expected to reach Asian markets after the anticipated Panama Canal expansion is completed (currently forecast for early 2016). This expansion project is expected to make LPG exports from the Gulf Coast to Asia more economical for shippers, allowing Asian importers to further diversify their sources of LPGs beyond their traditional Middle East suppliers. In 2014, U.S. ethane exports were generally limited to petrochemical customers in Canada that could receive volumes by pipeline.

Due to the renewed focus on hydrocarbon exports, we are actively growing our ability to provide services and products to Gulf Coast exporters. We are currently the largest supplier of propane to such exporters, and are nearly doubling the LPG export capacity at our Houston Ship Channel terminal over the next 18 months. In April 2014, we commenced construction of a large-scale marine ethane export facility, which will be located at Morgan's Point on the Houston Ship Channel. Our ethane export dock will be strategically linked to our Mont Belvieu storage, fractionation and pipeline assets. The construction and operation of the ethane export dock is supported by long-term commitments for approximately 80% of the facility's projected capacity and several customers have expressed interest in the remaining capacity and possible expansions.

In May 2014, we began loading cargoes of refined products for export on our reactivated marine terminal in Beaumont, Texas. We are also expanding this terminal with additional on-site storage and ancillary equipment for gasoline blending operations. Reactivation of the terminal, as well as its expansion, was supported by long-term customer commitments. With its strategic location and enhanced capabilities, the Beaumont Refined Products Export Terminal provides optionality for exporters, allowing them to capture added value from the evolving fundamentals of the domestic and international refined products markets.

In October 2014, we completed Step 1 of the Oiltanking acquisition (see "Significant Recent Developments" within this Part II, Item 7). In February 2015, the Oiltanking Merger was completed. The combination of our legacy midstream assets and Oiltanking's access to waterborne markets and crude oil and petroleum products storage assets extends and broadens our midstream energy services business. We believe this combination benefits our producing and consuming customers by enhancing their respective access to supplies, domestic and international markets, and storage.

In recent years, natural gas and NGLs developed a significant feedstock price advantage over more costly crude oil derivatives (such as naphtha). We expect this trend to continue based on energy prices quoted on futures markets in January 2015 and due to: (i) ongoing production from domestic shale resource plays and efforts by producers to lower associated drilling costs; (ii) anticipated increases in demand for crude oil by China, India and other developing economies; and (iii) geopolitical risks in many areas of the world that are major exporters of crude oil, which may cause unexpected crude oil price increases. In addition, this trend is supported in the near term by a

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lack of meaningful infrastructure to export natural gas and ethane supplies from the U.S., which results in an oversupply and lower market values for both energy commodities.

As a result of the feedstock price advantage currently held by natural gas and NGLs, energy consumers in the industrial manufacturing and power generation sectors are continuing to adjust their feedstock and asset portfolios to consume increasing amounts of these commodities in their operations. In addition, we believe the feedstock price advantage of domestically-produced NGLs has led to a long-term fundamental change in feedstock selection by the U.S. petrochemical industry, which is the largest consumer of domestic NGLs. Since NGLs typically trade at a significant discount to crude oil, using NGLs as a feedstock generally provides a substantial cost advantage for U.S. petrochemical companies when compared to using naphtha, whose price is closely linked to international crude prices. From 2009 through 2014, ethane and propane have generally been the most profitable feedstocks in the production of ethylene. In order to capitalize on this cost advantage, U.S. petrochemical companies have maximized their consumption of domestic NGLs, particularly ethane, in the production of ethylene. Many of these companies have also announced plans to invest billions of dollars to construct NGL feedstock-oriented, world-scale ethylene plants on the Gulf Coast. For example:

§	CP Chemical announced in December 2011 that it expects to build a 1.5 million metric tons per year ethylene plant in Cedar Bayou, Texas by 2017;

§	Formosa Plastics announced in March 2012 that it expects to build an 800 thousand metric tons per year ethylene plant along the U.S. Gulf Coast by 2016/2017;

§	Dow Chemical announced in April 2012 that it expects to build a 1.5 million metric tons per year ethylene plant along the U.S. Gulf Coast by 2017;

§	Sasol announced in October 2014 that they had reached final approval to build a 1.5 million metric ton per year ethylene plant in Lake Charles Louisiana; and

§	numerous other petrochemical companies have announced significant expansions and or conversions to ethane for at existing facilities.

Almost all of these ethylene plants and the ethylene industry's major expansions are in close proximity to our existing or planned assets, including our Aegis Ethane Pipeline.

Based on industry publications, domestic production of ethylene in 2014 was estimated to be 145 million pounds per day compared to 148 million pounds per day in 2013. Ethane is the most widely used feedstock by the U.S. petrochemical industry in the production of ethylene. As a result, ethane consumption by domestic petrochemical companies has, at times, been in excess of 1.1 MMBPD. We believe the U.S. ethylene industry could consume approximately 200 MBPD of additional ethane feedstocks over the next few years through modifications, debottlenecking and expansions at existing facilities. In addition, we believe that announced new petrochemical plant construction projects, including those noted in the preceding paragraph, could consume well over 500 MBPD of additional ethane feedstocks when completed. However, for almost all of 2014, ethane production was in excess of the ethylene industry's ability to consume ethane, resulting in significant volumes of ethane not being extracted from the natural gas stream by producers and natural gas processors in an effort to balance ethane supply to demand. In the absence of additional near-term demand growth or a significant drop in production, we expect ethane to remain oversupplied. This could lower the value of our equity NGL production and reduce the volumes that would otherwise be handled by our downstream NGL fractionators and pipelines.

Drilling activity in shale plays with predominantly dry natural gas production or natural gas production with a lower NGL content (e.g., the Haynesville/Bossier, Barnett, Fayetteville, Piceance and Jonah/Pinedale shales) are expected to remain well below peak levels. As a result, we expect that natural gas volumes on pipelines that serve these supply basins, including our Jonah, Piceance Basin, San Juan and Haynesville gathering systems, may decline further in 2015 when compared to 2014. Although these supply basins are currently experiencing production declines, we believe that these areas have substantial, undeveloped natural gas reserves with some of the lowest development and production costs in the U.S. Furthermore, we believe that as U.S. supply and demand for natural gas and ethane becomes more balanced through exports of these commodities and, as a result, natural gas

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and ethane prices stabilize and increase, these supply basins could experience an increase in drilling activity to support, and potentially increase, their future production levels.

With respect to the Gulf of Mexico, we expect that transportation volumes on our offshore crude oil pipelines will continue to increase in the near term as significant deepwater prospects begin production. For example, our SEKCO Oil Pipeline, which serves the Lucius field located in the southern Keathley Canyon area of the deepwater central Gulf of Mexico, commenced operations during the first quarter of 2015. Conversely, we expect that throughput volumes on our offshore Gulf of Mexico natural gas pipelines will continue to decline in 2015 due to producers focusing more of their near-term resources to exploit offshore crude oil developments and onshore NGL-rich natural gas and crude oil producing areas; however, increases in natural gas production associated with oil production are expected to temper the overall decline in Gulf of Mexico natural gas production. Development of hydrocarbon reserves in the Gulf of Mexico is capital intensive and projects typically have long lead times. At this time, we are uncertain what, if any, effect the current environment of lower hydrocarbon prices will have on producers' intermediate plans to explore and develop reserves in the Gulf of Mexico.

As a result of crude oil pipeline infrastructure expansions, including the Seaway Pipeline looping project we placed into service in 2014, producers have greater access to U.S. Gulf Coast refineries. This is evident in a significant narrowing of the differential in 2014 between Light Louisiana Sweet ("LLS") and West Texas Intermediate ("WTI"), which saw the premium of LLS compared to WTI (based on their average indicative price spread) narrow from $9.35 per barrel in 2013 to $3.61 per barrel in 2014 and $1.56 per barrel at the end of January 2015. The narrowing of the premium was a direct result of over 1.2 MMBPD of new pipeline capacity being placed into service between the Cushing hub and the U.S. Gulf Coast in 2014. With approximately 8.5 MMBPD of refining capacity along the Gulf Coast, refiners now have access to a wide array of crude types from which to choose, and will vary their crude input stream by employing a mix of domestic production with waterborne imports in order to optimize their operations and profitability. As a result of increasing domestic supplies, the U.S. Gulf Coast has seen crude oil imports fall from 3.7 MMBPD in 2013 to 3.4 MMBPD in 2014, while refinery crude runs on the Gulf Coast increased from 8.1 MMBPD in 2013 to 8.3 MMBPD in 2014. Many domestic refineries are modifying and expanding their facilities in order to process more North American crude oil and are also increasing their refined product exports in order to capture market share in emerging economies, which typically have insufficient refining capacity to satisfy their growing demand. We believe that this increased reliance on domestically-produced crudes will continue in 2015, with refiners further reducing their imports of waterborne crudes (particularly "light sweet" crudes). This trend should have a beneficial impact on our crude oil pipeline and storage assets and our refined product export facilities in 2015; however, this outlook may be compromised if there is a prolonged reduction in domestic crude oil drilling and production, or if overseas crude markets become discounted compared to the U.S. Gulf Coast for an extended period.

Liquidity Outlook for 2015

At December 31, 2014, we had $4.17 billion of consolidated liquidity, which was comprised of $74.4 million of unrestricted cash on hand and $4.09 billion of available borrowing capacity under EPO's revolving credit facilities. Throughout 2014, the corporate debt and equity capital markets were accessible to us, along with adequate credit availability from banks. Based on current market conditions (as of the filing date of this annual 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 have $2.05 billion of senior notes maturing in 2015 through the first quarter of 2016. We expect to refinance these senior note obligations at or prior to their maturity. The U.S. government is expected to continue to run substantial annual budget deficits in the coming years that will require a corresponding issuance of debt by the U.S. Treasury. The interest rate on U.S. Treasury debt has a direct impact on the cost of our debt. At this time, we are uncertain what impact the expected large issuances of U.S. Treasury debt and the prevailing economic and capital market conditions during these future periods will have on the cost and availability of capital, and we have not executed any interest rate swaps to hedge a portion of our expected future debt issuances in connection with the refinancing of debt. We continue to monitor and evaluate the condition of the capital markets and our interest rate risk with respect to refinancing these maturities and funding our capital spending program.

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For information regarding our capital spending program, including projected 2015 spending levels, see "Capital Spending" within this Part II, Item 7.

Results of Operations

Summarized Consolidated Income Statement Data

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

	For the Year Ended December 31,
	2014			2013			2012
Revenues	$	47,951.2		$	47,727.0		$	42,583.1
Costs and expenses:
Operating costs and expenses:
Cost of sales		40,464.1			40,770.2			36,015.5
Other operating costs and expenses		2,541.8			2,310.4			2,244.9
Depreciation, amortization and accretion expenses		1,282.7			1,148.9			1,061.7
Net gains attributable to asset sales and insurance recoveries		(102.1	)		(83.4	)		(17.6	)
Non-cash asset impairment charges		34.0			92.6			63.4
Total operating costs and expenses		44,220.5			44,238.7			39,367.9
General and administrative costs		214.5			188.3			170.3
Total costs and expenses		44,435.0			44,427.0			39,538.2
Equity in income of unconsolidated affiliates		259.5			167.3			64.3
Operating income		3,775.7			3,467.3			3,109.2
Interest expense		(921.0	)		(802.5	)		(771.8	)
Other, net		1.9			(0.2	)		73.4
Benefit from (provision for) income taxes		(23.1	)		(57.5	)		17.2
Net income		2,833.5			2,607.1			2,428.0
Net income attributable to noncontrolling interests		(46.1	)		(10.2	)		(8.1	)
Net income attributable to limited partners	$	2,787.4		$	2,596.9		$	2,419.9

Consolidated Revenues

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

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

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Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. Our largest non-affiliated customer for 2014 was Shell Oil Company and its affiliates ("Shell"), which accounted for $4.05 billion, or 8.5%, of our consolidated revenues for the year. The following table presents our consolidated revenues from Shell by business segment for the year ended December 31, 2014 (dollars in millions):

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

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

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)

2012 Averages	$	2.79	$	0.40	$	1.00	$	1.65	$	1.81	$	2.15	$	0.60	$	0.49	$	94.20	$	111.72

2013 by quarter:
1st Quarter	$	3.34	$	0.26	$	0.86	$	1.58	$	1.65	$	2.23	$	0.75	$	0.65	$	94.37	$	113.93
2nd Quarter	$	4.10	$	0.27	$	0.91	$	1.24	$	1.27	$	2.04	$	0.63	$	0.53	$	94.22	$	104.63
3rd Quarter	$	3.58	$	0.25	$	1.03	$	1.33	$	1.35	$	2.15	$	0.68	$	0.58	$	105.82	$	109.89
4th Quarter	$	3.60	$	0.26	$	1.20	$	1.43	$	1.45	$	2.10	$	0.68	$	0.56	$	97.46	$	100.94
2013 Averages	$	3.65	$	0.26	$	1.00	$	1.39	$	1.43	$	2.13	$	0.69	$	0.58	$	97.97	$	107.34

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

(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.

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 $0.97 per gallon for 2014 compared to $1.02 per gallon for 2013 – a 5% year-to-year decrease. With the collapse in crude oil prices in late 2014, the weighted-average indicative market price for NGLs for the fourth quarter of 2014

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was $0.74 per gallon. NGL prices are expected to follow crude oil prices in 2015, with some measure of recovery expected by the end of 2015.

According to the U.S. Energy Information Administration, ethane volumes account for approximately 35% of NGLs produced from natural gas processing activities. As a result of producers allocating more of their capital budgets to developing NGL-rich shale plays and their success in extracting such resources, ethane production has increased more rapidly than the ethylene industry's current capability to consume the increase in supplies. As a result of this trend, ethane prices declined to an average of $0.26 per gallon in 2013 from an average of $0.40 per gallon in 2012. Ethane prices in 2014 averaged $0.27 per gallon as ethane production growth was tempered by ethane rejection at natural gas processing plants; however, average ethane prices decreased to $0.21 per gallon in the fourth quarter of 2014 mirroring the general decline in energy prices.

§	The market price of natural gas (as measured at the Henry Hub in Louisiana) averaged $4.43 per MMBtu for 2014 compared to $3.65 per MMBtu during 2013 – a 21% year-to-year increase. The increase in prices is generally due to higher natural gas demand for power generation and as a heating fuel.

The market price of WTI crude oil (as measured on the NYMEX) averaged $93.01 per barrel for 2014 compared to $97.97 per barrel for 2013. Although average WTI prices declined only 5% year-to-year, they (along with other crude oil price benchmarks) declined sharply in the fourth quarter of 2014 to an average of $73.15 per barrel (hitting a low in December 2014 of $53.27 per barrel). In January 2015, WTI crude oil prices averaged $47.33 per barrel. See "Commercial Outlook for 2015" within this Part II, Item 7 for a discussion of the recent decline in global crude oil prices and its potential impact on our operations.

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 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our commodity hedging activities.

Consolidated Income Statement Highlights

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

Comparison of 2014 with 2013

Revenues. Revenues for 2014 increased $224.2 million when compared to revenues for 2013. Revenues from the marketing of natural gas increased $609.9 million year-to-year primarily due to higher sales prices, which accounted for a $534.7 million increase. Revenues from the marketing of refined products increased a net $435.7 million year-to-year primarily due to higher sales prices, which accounted for a $502.5 million increase, partially offset by lower sales volumes, which accounted for a $66.8 million decrease. Revenues from the marketing of crude oil decreased a net $584.5 million year-to-year primarily due to lower sales prices, which accounted for a $4.59 billion decrease, partially offset by higher sales volumes, which accounted for a $4.01 billion increase. Revenues from the marketing of NGLs decreased $455.9 million year-to-year primarily due to lower sales prices, which accounted for a $254.8 million decrease, and lower sales volumes, which accounted for an additional $201.1 million decrease. Collectively, revenues from the marketing of octane additives and high purity isobutylene ("HPIB") decreased $434.0 million year-to-year primarily due to lower sales volumes, which in turn were attributable to lower production volumes caused by unscheduled plant maintenance outages.

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Revenues from midstream services increased $648.0 million year-to-year primarily due to the ongoing expansion of our operations. Recently completed assets such as the ATEX pipeline and the Rocky Mountain expansion of our Mid-America Pipeline System as well as certain assets in the Eagle Ford Shale and at our Mont Belvieu complex contributed approximately $400 million of this increase. Also, our consolidated revenues for the fourth quarter of 2014 include $57.5 million from Oiltanking's operations. On October 1, 2014, we acquired a controlling financial interest in Oiltanking; therefore, we began consolidating the financial results of Oiltanking on this date. For additional information regarding the Oiltanking acquisition, see "Significant Recent Developments" within this Part II, Item 7.

Operating costs and expenses. Total operating costs and expenses for 2014 decreased $18.2 million when compared to 2013. The cost of sales associated with our marketing of natural gas increased $343.5 million year-to-year primarily due to higher purchase prices, which accounted for a $283.8 million increase. Cost of sales associated with our marketing of refined products increased a net $400.4 million year-to-year primarily due to higher purchase prices, which accounted for a $469.5 million increase, partially offset by lower sales volumes, which accounted for a $69.1 million decrease. Cost of sales associated with our marketing of crude oil decreased a net $405.7 million year-to-year primarily due to lower purchase costs, which accounted for a $4.25 billion decrease, partially offset by higher sales volumes, which accounted for a $3.84 billion increase. The cost of sales associated with our marketing of NGLs decreased $383.7 million year-to-year primarily due to lower sales volumes, which accounted for a $255.3 million decrease, and lower purchase costs, which accounted for an additional $128.4 million decrease. Collectively, the cost of sales associated with our marketing of octane additives and HPIB decreased $261.7 million year-to-year primarily due to lower purchase costs, which accounted for a $160.9 million decrease, and lower sales volumes, which accounted for an additional $100.8 million decrease.

Other operating costs and expenses increased $231.4 million year-to-year. The primary driver of this increase is the ongoing expansion of our operations, including that associated with recently completed assets being placed into service (e.g., our ATEX pipeline and expansion of the Rocky Mountain segment of our Mid-America Pipeline System). We estimate that asset expansions accounted for approximately $125.0 million of the $231.4 million increase in expense. In addition, the year-to-year increase includes $18.0 million of expense we recorded in 2014 in connection with a producer settlement involving our San Juan Gathering System and a $16.6 million benefit we recognized in 2013, which represents a negative variance year-to-year, attributable to reductions in a provision for certain pipeline capacity obligations. Other operating costs and expenses for 2014 also include $14.8 million of expenses attributable to Oiltanking's operations in the fourth quarter of 2014.

Depreciation, amortization and accretion expenses in operating costs and expenses increased $133.8 million in 2014 when compared to 2013 primarily due to recently constructed assets being placed into service. Depreciation and amortization expense for 2014 includes $25.0 million attributable to Oiltanking for the fourth quarter of 2014.

We recorded net gains within operating costs and expenses of $102.1 million attributable to asset sales and insurance recoveries in 2014 compared to $83.4 million in 2013. We recognized $95.0 million of gains attributable to the receipt of nonrefundable cash insurance proceeds related to our West Storage claims in 2014 compared to $15.0 million of such gains in 2013. 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. In March 2013, we sold the Stratton Ridge-to-Mont Belvieu segment of the Seminole Pipeline, along with a related storage cavern, and recognized a $52.5 million gain on the sale.

General and administrative costs. General and administrative costs for 2014 increased $26.2 million when compared to 2013 primarily due to higher employee compensation costs, which accounted for $17.3 million of the increase, transaction costs of $3.8 million associated with Step 1 of the Oiltanking acquisition, and $4.7 million of expense for the settlement of litigation.

Equity in income of unconsolidated affiliates. Equity income from our unconsolidated affiliates increased $92.2 million in 2014 when compared to 2013. This increase was primarily due to increased earnings from our investments in crude oil pipeline joint ventures.

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Interest expense. Interest expense for 2014 increased $118.5 million when compared to 2013. The following table presents the components of our consolidated interest expense for the years indicated (dollars in millions):

	For the Year Ended December 31,
	2014			2013
Interest charged on debt principal outstanding	$	969.1		$	911.7
Impact of interest rate hedging program, including related amortization		9.4			3.3
Interest cost capitalized in connection with construction projects (1)		(77.9	)		(133.0	)
Other (2)		20.4			20.5
Interest expense	$	921.0		$	802.5

(1) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. 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. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate from period-to-period 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 increased a net $57.4 million year-to-year primarily due to increased debt principal amounts outstanding during 2014, which accounted for a $97.9 million increase, partially offset by the effect of lower overall interest rates in 2014, which accounted for a $40.5 million decrease. Our weighted-average debt principal balance for 2014 was $18.96 billion compared to $17.14 billion for 2013. Our debt principal balances have increased over time primarily due to the partial debt financing of our capital spending program. Capitalized interest decreased $55.1 million year-to-year primarily due to assets being placed into service. For a discussion of our consolidated debt obligations and capital spending program, see "Liquidity and Capital Resources" within this Part II, Item 7.

Income taxes. Provision for income taxes decreased $34.4 million in 2014 when compared to 2013. The decrease was primarily due to changes in our accruals for state tax obligations under the Revised Texas Franchise Tax (or "Texas Margin Tax"). For additional information regarding our income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Noncontrolling interests. Net income attributable to noncontrolling interests increased $35.9 million in 2014 primarily due to increased earnings from the underlying joint ventures and the inclusion of noncontrolling interests in Oiltanking effective October 1, 2014.

Comparison of 2013 with 2012

Revenues. Revenues for 2013 increased $5.14 billion when compared to revenues for 2012. Revenues from the marketing of crude oil increased $2.83 billion year-to-year primarily due to higher sales volumes, which accounted for a $2.28 billion increase, and sales prices, which accounted for an additional $543.8 million increase. Revenues from the marketing of NGLs increased a net $1.7 billion year-to-year primarily due to higher sales volumes, which accounted for a $3.64 billion increase, partially offset by lower sales prices, which accounted for a $1.94 billion decrease. Revenues from the marketing of natural gas and petrochemical products increased a net $392.4 million year-to-year primarily due to higher sales prices, which accounted for a $1.1 billion increase, partially offset by lower sales volumes, which accounted for a $708.3 million decrease. Revenues from the marketing of refined products decreased a net $106.8 million year-to-year primarily due to lower sales prices, which accounted for a $697.7 million decrease, which was partially offset by the impact of higher sales volumes, which accounted for a $590.9 million increase. Revenues from midstream asset services increased $347.2 million year-to-year primarily due to the timing of newly constructed assets being placed into service during these years, particularly those assets associated with the Eagle Ford Shale and at our Mont Belvieu complex.

Operating costs and expenses. Total operating costs and expenses for 2013 increased $4.87 billion when compared to 2012 primarily due to a $4.75 billion increase in cost of sales. The cost of sales associated with our marketing of crude oil increased $2.59 billion year-to-year primarily due to higher sales volumes, which accounted

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for a $2.15 billion increase, and purchase prices, which accounted for an additional $440.1 million increase. Cost of sales associated with the marketing of NGLs increased a net $1.95 billion year-to-year primarily due to higher sales volumes, which accounted for a $3.36 billion increase, partially offset by lower purchase prices, which accounted for a $1.41 billion decrease. Cost of sales associated with our marketing of natural gas and petrochemical products increased a net $377.2 million year-to-year primarily due to higher purchase prices, which accounted for a $1.02 billion increase, partially offset by lower sales volumes, which accounted for a $643.4 million decrease. Cost of sales associated with the marketing of refined products decreased a net $105.1 million year-to-year primarily due to lower purchase prices, which accounted for a $733.9 million decrease, which was partially offset by the impact of higher sales volumes, which accounted for a $628.8 million increase.

Other operating costs and expenses increased a net $65.5 million year-to-year, which includes a $188.8 million increase primarily due to the addition of operating costs of newly constructed assets and higher overall maintenance costs, partially offset by a $123.3 million reduction in operating costs due to the sale of certain trucking and distribution assets in January and April 2013.

Depreciation, amortization and accretion expenses in operating costs and expenses increased $87.2 million for 2013 when compared to 2012 primarily due to the timing of newly constructed assets being placed into service during these periods.

We recorded net gains within operating costs and expenses of $83.4 million attributable to asset sales and insurance recoveries in 2013 compared to $17.6 million in 2012. In March 2013, we sold the Stratton Ridge-to-Mont Belvieu segment of the Seminole Pipeline, along with a related storage cavern, and recognized a $52.5 million gain on the sale. Also, we recognized $15.0 million of gains in 2013 attributable to the receipt of nonrefundable cash insurance proceeds for claims resulting from the 2011 NGL release and fire at our West Storage location. We recognized $30.0 million of such gains in 2012.

Operating costs and expenses include $92.6 million and $63.4 million of non-cash asset impairment charges in 2013 and 2012, respectively. Our non-cash asset impairment charges for 2013 primarily relate to the abandonment of certain segments of crude oil and natural gas pipelines in Texas, Oklahoma and the Gulf of Mexico, certain refined products terminal assets in Texas, an NGL storage cavern in Arizona and an NGL fractionator and storage complex in Ohio. Our asset impairment charges for 2012 primarily relate to the abandonment of certain segments of crude oil and natural gas pipelines in Texas and the Gulf of Mexico.

General and administrative costs. General and administrative costs for 2013 increased $18.0 million when compared to 2012 primarily due to higher employee compensation expenses.

Equity in income of unconsolidated affiliates. Equity income from our unconsolidated affiliates for 2013 increased $103.0 million when compared to 2012 primarily due to higher earnings from our investments in crude oil pipeline joint ventures.

Interest expense. Interest expense for 2013 increased $30.7 million when compared to 2012. The following table presents the components of our consolidated interest expense for the years indicated (dollars in millions):

	For the Year Ended December 31,
	2013			2012
Interest charged on debt principal outstanding	$	911.7		$	879.7
Impact of interest rate hedging program, including related amortization		3.3			(12.6	)
Interest cost capitalized in connection with construction projects		(133.0	)		(116.8	)
Other		20.5			21.5
Interest expense	$	802.5		$	771.8

Interest charged on debt principal outstanding increased a net $32.0 million for 2013 when compared to 2012 generally due to increased debt principal amounts outstanding during 2013, which accounted for $94.5 million of the increase, partially offset by the effect of lower overall interest rates in 2013, which accounted for a $62.5 million decrease. Our weighted-average debt principal balance for 2013 was $17.14 billion compared to $15.3

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billion for 2012. As noted previously, our debt principal balances have increased over time due to the partial debt financing of our capital spending program.

Other income. Other non-operating income for 2012 includes $68.8 million of aggregate gains attributable to the liquidation of our investment in Energy Transfer Equity, L.P. ("Energy Transfer Equity"). At January 1, 2012, we owned 29,303,514 common units of Energy Transfer Equity representing 13.1% of its limited partner interests. On January 18, 2012, we sold 22,762,636 of these common units in a private transaction, which generated a gain on the sale of $27.5 million. As a result of the January 18, 2012 transaction, our ownership interest in Energy Transfer Equity was reduced below 3%, and we discontinued using the equity method to account for this investment and began accounting for it as an investment in available-for-sale equity securities. Following the January 18, 2012 transaction, we sold the remaining 6,540,878 Energy Transfer Equity common units through April 27, 2012, which generated gains totaling $41.3 million. All activities included in our former sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our investment in Energy Transfer Equity. See Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding our business segments.

Income taxes. Provision for income taxes was $57.5 million in 2013, which primarily reflects our state tax obligations under the Texas Margin Tax. However, we recognized an overall income tax benefit of $17.2 million for 2012, which was primarily due to a $45.3 million federal income tax benefit related to the conversion of certain of our subsidiaries to limited liability companies during the first quarter of 2012, partially offset by amounts recorded in connection with the Texas Margin Tax. For additional information regarding our provision for income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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 Year Ended December 31,
	2014		2013		2012
NGL Pipelines & Services	$	2,877.7	$	2,514.4	$	2,468.5
Onshore Natural Gas Pipelines & Services		803.3		789.0		775.5
Onshore Crude Oil Pipelines & Services		762.5		742.7		387.7
Offshore Pipeline & Services		162.0		146.1		173.0
Petrochemical & Refined Products Services		681.0		625.9		579.9
Other (1)		--		--		2.4
Total	$	5,286.5	$	4,818.1	$	4,387.0

(1) Represents the equity earnings we recorded from our previously held investment in Energy Transfer Equity. Our reporting for this segment ceased on January 18, 2012 when we stopped using the equity method to account for this investment. See Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding the liquidation of our investment in Energy Transfer Equity.

For additional information regarding our use of this non-GAAP financial measure, see "Other Items – Use of Non-GAAP Financial Measures" within this Part II, Item 7.

We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income.

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

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

	For the Year Ended December 31,
	2014		2013		2012
Segment gross operating margin:
Natural gas processing and related NGL marketing activities	$	1,162.0	$	1,165.4	$	1,443.0
NGL pipelines and related storage		1,145.7		900.0		740.7
NGL fractionation		570.0		449.0		284.8
Total	$	2,877.7	$	2,514.4	$	2,468.5
Selected volumetric data:
NGL transportation volumes (MBPD)		2,892		2,787		2,472
NGL fractionation volumes (MBPD)		824		726		659
Equity NGL production (MBPD) (1)		116		126		101
Fee-based natural gas processing (MMcf/d) (2)		4,786		4,612		4,382

(1) The increase in 2013 compared to 2012 is primarily due to equity NGL volumes produced at our Yoakum facility in South Texas. (2) Volumes reported correspond to the revenue streams earned by our gas plants. The increase in fee-based processing volumes in 2013 from 2012 is primarily due to (i) the start-up of our Yoakum gas plant in May 2012 and (ii) changes in processing agreements whereby producers are electing to process more of their natural gas on a fee basis in order to retain NGLs extracted from their natural gas streams, which, in turn, also lowers our equity NGL production.

Natural gas processing and related NGL marketing activities

Comparison of 2014 with 2013. Gross operating margin from natural gas processing and related NGL marketing activities for 2014 decreased $3.4 million when compared to 2013. Gross operating margin from our NGL marketing activities for 2014 decreased a net $28.4 million when compared to 2013 primarily due to lower sales margins, which accounted for a $52.9 million decrease, partially offset by a $23.4 million increase due to higher sales volumes, especially for fully-refrigerated, low-ethane propane volumes at our Houston Ship Channel LPG export dock. LPG exports continue to benefit from increased NGL supplies produced from domestic shale plays such as the Eagle Ford Shale and international demand for propane as a feedstock in ethylene plant operations and for power generation and heating purposes.

Gross operating margin from our Pioneer natural gas processing plant increased a net $35.0 million year-to-year primarily due to higher equity NGL production volumes of 6 MBPD, which accounted for a $42.4 million increase, partially offset by lower processing margins, which accounted for a $12.6 million decrease. Gross operating margin from our South Texas natural gas processing plants increased a net $49.9 million year-to-year primarily due to (i) higher processing fees, which accounted for a $24.8 million increase, (ii) higher fee-based processing volumes of 162 MMcf/d, which accounted for a $13.4 million increase and (iii) higher processing margins, which accounted for a $25.2 million increase. Equity NGL production volumes at our South Texas natural gas processing plants decreased 9 MBPD year-to-year, which resulted in a $14.5 million decrease in gross operating margin.

Gross operating margin from our Meeker natural gas processing plant decreased a net $38.0 million year-to-year primarily due to (i) lower processing margins, which accounted for a $19.8 million decrease, (ii) lower equity NGL production volumes of 15 MBPD, which accounted for a $21.9 million decrease, (iii) lower fee based processing volumes of 160 MMcf/d, which accounted for a $9.9 million decrease, partially offset by (iii) higher processing fees, which accounted for a $12.3 million increase. Gross operating margin from our natural gas processing plants in southern Louisiana decreased a net $14.3 million year-to-year primarily due (i) to lower processing margins, which accounted for a $23.6 million decrease, and (ii) lower processing fees, which accounted for a $6.9 million decrease, partially offset by (iii) higher equity NGL production of 7 MBPD, which accounted for an $18.4 million increase. Gross operating margin from our Chaco gas plant decreased $12.1 million year-to-year primarily due to lower processing margins, which accounted for a $5.7 million decrease, and higher operating expenses of $8.4 million associated with plant maintenance projects.

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Comparison of 2013 with 2012. Gross operating margin from our natural gas processing and related NGL marketing activities for 2013 decreased $277.6 million when compared to 2012. Gross operating margin from our Meeker natural gas processing plant in Colorado decreased $182.4 million year-to-year primarily due to lower processing margins in 2013. Gross operating margin from our Pioneer natural gas processing plant in Wyoming decreased $81.3 million year-to-year primarily due to the effects of ethane rejection and general production declines, both of which lowered equity NGL production volumes at this facility during 2013 when compared to 2012.

Gross operating margin from our South Texas natural gas processing plants increased a net $15.9 million year-to-year primarily due to higher volumes, which accounted for a $54.3 million increase, and higher processing fees, which resulted in a $28.6 million increase, partially offset by lower processing margins, which accounted for a $65.3 million decrease. Results from our South Texas natural gas processing plants benefited from the start-up of our Yoakum, Texas gas plant. The first phase (or "train") of this plant commenced operations in May 2012. We placed the second and third trains at the Yoakum plant in service in August 2012 and March 2013, respectively. Gross operating margin from our remaining natural gas processing plants decreased a combined $40.4 million year-to-year primarily due to lower processing margins in 2013.

Gross operating margin from our NGL marketing activities for 2013 increased a net $44.3 million when compared to 2012 primarily due to higher sales volumes, which accounted for a $131.0 million increase, partially offset by lower sales margins, which accounted for an $87.0 million decrease.

Comparability between 2013 and 2012 gross operating margin amounts was also impacted by a $20.0 million gain related to proceeds received in a vendor settlement and a $13.7 million gain attributable to changes in a provision for certain gas plant capacity obligations, both of which were recorded in 2012.

NGL pipelines and related storage

Comparison of 2014 with 2013. Gross operating margin from NGL pipelines and related storage assets for 2014 increased $245.7 million when compared to 2013. Our ATEX pipeline, which commenced operations in January 2014, contributed $135.6 million of gross operating margin in 2014 and 53 MBPD of transportation volumes. ATEX transports ethane primarily southbound from NGL fractionation plants located in Pennsylvania, West Virginia and Ohio to our Mont Belvieu storage complex. The ethane extracted by these fractionation facilities originates from the Marcellus and Utica Shale production areas. Gross operating margin for ATEX for 2014 includes $55.2 million of transportation revenues associated with shipper make-up rights that are deferred under GAAP and not reflected in our consolidated revenues. For additional information regarding the inclusion of deferred revenues in gross operating margin, see "Other Items – Use of Non-GAAP Financial Measures – Gross Operating Margin" within this Part II, Item 7.

Gross operating margin from our Mid-America Pipeline System, Seminole Pipeline and related NGL terminals increased a net $50.5 million year-to-year. The increase in gross operating margin is primarily due to a $103.9 million increase in transportation revenues attributable to the Rocky Mountain pipeline expansion and higher system-wide tariffs, partially offset by a $27.2 million increase in operating costs (e.g., higher fuel and maintenance costs) and a $26.2 million decrease in revenues attributable to a 47 MBPD decline in transportation volumes. Gross operating margin from our South Texas NGL Pipeline System increased $18.0 million year-to-year primarily due to a 35 MBPD increase in transportation volumes primarily associated with Eagle Ford Shale production.

Collectively, gross operating margin from our investments in the Front Range Pipeline, Texas Express Pipeline and Texas Express Gathering System increased $23.9 million year-to-year. The year-to-year increase in gross operating margin from these investments includes $7.4 million of 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. Net to our interest, aggregate transportation volumes on these three pipeline systems were 60 MBPD in 2014. The Front Range Pipeline, which commenced operations in February 2014, transports mixed NGLs from natural gas processing plants located in the Denver-Julesburg Basin in Colorado to an interconnect with our Texas Express Pipeline and Mid-America Pipeline System at Skellytown, Texas. The Texas Express Pipeline extends from Skellytown, Texas to our NGL fractionation and storage complex at Mont Belvieu, Texas. The Texas Express Gathering System is comprised of two NGL gathering systems that deliver volumes to the Texas Express

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Pipeline. The Texas Express Pipeline and Texas Express Gathering System both commenced operations in November 2013.

Gross operating margin for the fourth quarter of 2014 includes $19.3 million from Oiltanking attributable to fees it charges Enterprise for use of Oiltanking's Houston Ship Channel docks and related infrastructure to load and unload NGLs. Enterprise's Houston Ship Channel LPG export and NGL import marine terminal are located on land owned by Oiltanking at its Jacintoport facility.

Comparison of 2013 with 2012. Gross operating margin from NGL pipelines and related storage assets for 2013 increased $159.3 million when compared to 2012 primarily due to strong results from our South Texas and Houston region NGL assets and the Dixie Pipeline. Gross operating margin from our South Texas NGL Pipeline System increased $66.6 million year-to-year primarily due to a 126 MBPD increase in transportation volumes associated with Eagle Ford Shale production.

Gross operating margin from our Houston Ship Channel LPG export terminal and related Channel Pipeline increased a combined $50.0 million year-to-year primarily due to increased volumes. In March 2013, we completed an expansion project at this terminal that increased its loading capability for fully refrigerated, low-ethane propane from 4.0 MMBbls per month to 7.5 MMBbls per month. Loading volumes at our Houston Ship Channel LPG export terminal increased 99 MBPD year-to-year and volumes transported on the related Channel Pipeline increased 108 MBPD year-to-year.

Gross operating margin from our Dixie Pipeline and related NGL terminals increased $18.2 million year-to-year primarily due to a 27 MBPD increase in transportation volumes for 2013, which accounted for $10.7 million of the increase after taking into account associated operating costs, and higher transportation and other fees, which accounted for $7.5 million of the increase. Transportation volumes on the Dixie Pipeline were negatively impacted during 2012 due to downtime associated with pipeline integrity projects and warmer than normal winter weather.

Gross operating margin from our Mid-America Pipeline System, Seminole Pipeline and related NGL terminals increased a net $7.2 million year-to-year. A $43.2 million increase in revenues associated with higher system-wide tariffs and other fees, combined with a $4.3 million decrease in operating costs primarily due to pipeline gains during 2013, was partially offset by a $40.3 million decrease in gross operating margin attributable to lower transportation volumes. Transportation volumes for our Mid-America Pipeline System and Seminole Pipeline decreased a combined 75 MBPD year-to-year primarily due to lower NGL production from Rocky Mountain natural gas processing plants caused by ethane rejection and reduced demand for NGL transportation services between Conway, Kansas and Mont Belvieu, Texas.

NGL fractionation

Comparison of 2014 with 2013. Gross operating margin from NGL fractionation for 2014 increased $121.0 million when compared to 2013 primarily due to higher fractionation volumes and fees at our Mont Belvieu complex. NGL fractionation volumes at our Mont Belvieu complex increased 108 MBPD year-to-year (net to our ownership interest), which resulted in a $113.2 million year-to-year increase in gross operating margin after taking into account associated operating costs. Higher average fractionation and other fees at our Mont Belvieu NGL fractionators accounted for an additional $22.8 million year-to-year increase in gross operating margin. Our Mont Belvieu NGL fractionators continue to benefit from increased mixed NGL volumes sourced from domestic shale plays such as the Eagle Ford and other producing regions such as the Rocky Mountains.

Comparison of 2013 with 2012. Gross operating margin from NGL fractionation for 2013 increased $164.2 million when compared to 2012 primarily due to higher fractionation fees and volumes at our Mont Belvieu complex. Higher average fractionation and other fees during 2013 attributable to our Mont Belvieu NGL fractionators accounted for an $82.4 million year-to-year increase in gross operating margin. Also, NGL fractionation volumes at our Mont Belvieu complex increased 97 MBPD year-to-year (net to our ownership interest), which resulted in a $61.1 million year-to-year increase in gross operating margin after taking into account associated operating costs. NGL fractionation capacity at our Mont Belvieu complex increased 170 MBPD year-to-year as a result of placing our seventh and eighth NGL fractionation units into service in the third and fourth quarters of 2013, respectively.

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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 years indicated (dollars in millions, volumes as noted):

	For the Year Ended December 31,
	2014		2013		2012
Segment gross operating margin	$	803.3	$	789.0	$	775.5
Selected volumetric data:
Natural gas transportation volumes (BBtus/d)		12,476		12,936		13,634

Comparison of 2014 with 2013. Gross operating margin from our onshore natural gas pipelines and services segment for 2014 increased $14.3 million when compared to 2013. Gross operating margin from our natural gas marketing activities increased $28.1 million year-to-year primarily due to higher sales margins, which includes a $13.6 million increase attributable to unrealized, non-cash mark-to-market losses in 2013 that did not reoccur in 2014.

Gross operating margin from our Texas Intrastate System increased $21.6 million year-to-year primarily due to higher pipeline and storage revenues in 2014, which accounted for a $19.2 million increase. Transportation revenues on the Texas Intrastate System increased $17.8 million year-to-year primarily due to higher average fees, which includes a $5.8 million year-to-year increase in firm capacity reservation fees primarily due to producer activity in the Eagle Ford Shale. The Texas Intrastate System continues to benefit from increased natural gas production from the Eagle Ford Shale, in large part a by-product of increased NGL and crude oil production. Overall, natural gas transportation volumes for the Texas Intrastate System increased 40 BBtus/d year-to-year.

Gross operating margin from our San Juan Gathering System decreased a net $8.2 million year-to-year primarily due to $18.0 million of expense in 2014 for the settlement of a contract dispute with a producer and a $4.4 million decrease attributable to lower gathering volumes, both of which were partially offset by a $12.2 million increase attributable to higher gathering fees, which are indexed to natural gas prices. Gross operating margin from our Jonah, Piceance Basin and Haynesville Gathering Systems decreased a combined $24.6 million year-to-year primarily due to lower gathering volumes. Producers served by these four gathering systems have curtailed their drilling programs in response to the continued low price of natural gas. Collectively, natural gas transportation volumes for these four gathering systems decreased 412 BBtus/d year-to-year.

Comparison of 2013 with 2012. Gross operating margin from onshore natural gas pipelines and services for 2013 increased $13.5 million when compared to 2012. Gross operating margin from our Texas Intrastate System increased $57.6 million year-to-year primarily due to higher transportation revenues. Natural gas transportation volumes for the Texas Intrastate System increased 206 BBtus/d year-to-year. Gross operating margin from our natural gas marketing activities increased $8.8 million year-to-year primarily due to higher sales margins.

Gross operating margin from our Jonah, Piceance Basin and Haynesville Gathering Systems decreased a combined $35.3 million year-to-year primarily due to lower gathering volumes. Gross operating margin from our San Juan Gathering System increased a net $0.4 million year-to-year primarily due to higher gathering fees, which are indexed to natural gas prices and accounted for a $16.2 million increase, partially offset by the effects of lower volumes, which accounted for a $15.8 million decrease. Collectively, natural gas transportation volumes for these four gathering systems decreased 805 BBtus/d year-to-year.

Gross operating margin from our Acadian Gas System decreased $14.4 million year-to-year primarily due to higher operating expenses, which accounted for $6.3 million of the decrease, and lower sales margins, which accounted for a $5.1 million decrease. Transportation volumes for our Acadian Gas System declined a net 63 BBtus/d year-to-year primarily due to lower volumes from the Haynesville supply basin.

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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 years indicated (dollars in millions, volumes as noted):

	For the Year Ended December 31,
	2014		2013		2012
Segment gross operating margin	$	762.5	$	742.7	$	387.7
Selected volumetric data:
Crude oil transportation volumes (MBPD)		1,278		1,175		828

Comparison of 2014 with 2013. Gross operating margin from our onshore crude oil pipelines and services segment for 2014 increased $19.8 million when compared to 2013. Gross operating margin from our crude oil marketing and related activities decreased $161.1 million year-to-year primarily due to lower sales margins attributable to decreases in regional price spreads for crude oil. For example, the average indicative price spread between LLS and WTI crude oil was $9.37 per barrel in 2013 compared to $3.74 per barrel in 2014.

Gross operating margin from our South Texas Crude Oil Pipeline System and West Texas System increased a combined $77.6 million year-to-year primarily due to a combined 58 MBPD increase in transportation volumes. Equity earnings from our investment in the Eagle Ford Crude Oil Pipeline System, which commenced operations in the second quarter of 2013, increased $28.2 million year-to-year on a 52 MBPD increase in transportation volumes (net to our interest).

Gross operating margin from our investment in the Seaway Pipeline increased $30.4 million year-to-year primarily due to higher average tariffs and other fees in 2014, including $9.0 million of capacity fees associated with the commencement of operations on the Seaway Loop in December 2014. The year-to-year increase in gross operating margin from this investment includes $16.7 million of 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 decreased a net 18 MBPD year-to-year (net to our interest), with a 42 MBPD decrease in short-haul volumes on the Texas City System partially offset by a 25 MBPD increase on the Freeport System.

Gross operating margin from our ECHO storage terminal increased $17.9 million year-to-year primarily due to an increase in net measurement gains of $8.9 million in 2014 when compared to 2013 and higher storage volumes, which accounted for an $8.6 million increase. Gross operating margin from crude oil and related operations at Oiltanking's Houston Ship Channel terminal was $35.3 million for the fourth quarter of 2014.

Comparison of 2013 with 2012. Gross operating margin from our onshore crude oil pipelines and services business for 2013 increased $355.0 million when compared to 2012 primarily due to higher volumes on our crude oil pipeline systems and improved results from our crude oil marketing activities. Gross operating margin from our South Texas Crude Oil Pipeline System increased $192.3 million year-to-year primarily due to a 107 MBPD increase in volumes on the Eagle Ford Expansion pipeline. Gross operating margin from our investments in the Eagle Ford Crude Oil Pipeline System and Seaway Pipeline increased a combined $110.6 million year-to-year primarily due to an aggregate 193 MBPD increase in transportation volumes (net to our interest) on these pipelines. We placed the Eagle Ford Crude Oil Pipeline System into service in July 2013. Results for Seaway benefited from the completion of pump station additions and modifications at its Cushing origin in January 2013. Lastly, gross operating margin from our crude oil marketing and related activities increased $30.3 million year-to-year primarily due to higher sales volumes.

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

	For the Year Ended December 31,
	2014		2013		2012
Segment gross operating margin	$	162.0	$	146.1	$	173.0
Selected volumetric data: (1)
Natural gas transportation volumes (BBtus/d)		627		678		853
Crude oil transportation volumes (MBPD)		330		307		300
Platform natural gas processing (MMcf/d)		145		202		291
Platform crude oil processing (MBPD)		14		16		17

Comparison of 2014 with 2013. Gross operating margin from our offshore pipelines and services segment for 2014 increased $15.9 million when compared to 2013. Gross operating margin for 2014 includes $14.3 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. Equity earnings from our investment in the Cameron Highway Oil Pipeline increased $5.0 million year-to-year primarily due to a 21 MBPD increase (net to our interest) in crude oil transportation volumes. Equity earnings from our investment in Neptune Pipeline Company, L.L.C. ("Neptune") increased $4.3 million year-to-year primarily due to its 2013 results including a $4.8 million non-cash impairment charge. Lastly, in the aggregate, gross operating margin from our Independence Hub platform and Independence Trail pipeline decreased $15.8 million year-to-year primarily due to lower platform processing and pipeline throughput volumes during 2014. Natural gas processing volumes on the Independence Hub platform decreased 70 MMcf/d year-to-year (net to our interest) and natural gas transportation volumes on the Independence Trail pipeline decreased 81 BBtus/d year-to-year.

Due to the high cost of third party windstorm insurance coverage for our offshore Gulf of Mexico assets, we have self-insured these operations since June 2012. For a discussion of insurance-related matters, see "Other Items – Insurance Matters" within this Part II, Item 7

Comparison of 2013 with 2012. Gross operating margin from our offshore pipelines and services business for 2013 decreased $26.9 million when compared to 2012. In the aggregate, gross operating margin from our Independence Hub platform and Independence Trail pipeline decreased $24.7 million year-to-year primarily due to the expiration of contractual platform demand fees during the first quarter of 2012, which accounted for $9.7 million of the decrease, and lower platform processing and pipeline throughput volumes during 2013, which accounted for $16.0 million of the decrease. Natural gas processing volumes on the Independence Hub platform decreased 88 MMcf/d year-to-year (71 MMcf/d net to our interest) and natural gas transportation volumes on the Independence Trail pipeline decreased 73 BBtus/d year-to-year. Gross operating margin from our High Island Offshore System ("HIOS") decreased $3.4 million year-to-year primarily due to a 37 BBtus/d decrease in natural gas transportation volumes. Equity earnings from our investment in Neptune include a $4.8 million non-cash impairment charge recorded in 2013.

Collectively, gross operating margin from our Shenzi and Constitution Oil Pipelines decreased $7.4 million year-to-year. These pipelines experienced a combined 13 MBPD decrease in throughput volumes primarily due to production declines. Equity earnings from our investment in the Cameron Highway Oil Pipeline increased $7.8 million year-to-year primarily due to a 22 MBPD increase (net to our interest) in crude oil transportation volumes.

Due to the high cost of third party windstorm insurance coverage for our offshore Gulf of Mexico assets, we have self-insured these operations since June 2012. As a result, insurance expense for this segment in 2013 decreased $6.5 million when compared to 2012. For a discussion of insurance-related matters, see "Other Items – Insurance Matters" within this Part II, Item 7.

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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 years indicated (dollars in millions, volumes as noted):

	For the Year Ended December 31,
	2014		2013		2012
Segment gross operating margin:
Propylene fractionation and related activities	$	227.4	$	134.7	$	193.1
Butane isomerization and related operations		75.3		99.2		95.8
Octane enhancement and related plant operations		122.4		154.7		100.9
Refined products pipelines and related activities		186.7		164.6		89.9
Marine transportation and other		69.2		72.7		100.2
Total	$	681.0	$	625.9	$	579.9
Selected volumetric data:
Propylene fractionation volumes (MBPD)		75		74		72
Butane isomerization volumes (MBPD)		93		94		95
Standalone DIB processing volumes (MBPD)		82		67		46
Octane additive and related plant production volumes (MBPD)		17		20		16
Transportation volumes, primarily refined products and petrochemicals (MBPD)		802		702		689

Propylene fractionation and related activities

Comparison of 2014 with 2013. Gross operating margin from our propylene fractionation and related activities increased $92.7 million for 2014 when compared to 2013. This increase was primarily due to (i) higher propylene sales margins, which accounted for a $55.0 million increase, (ii) higher propylene sales volumes, which accounted for an $8.8 million increase, (iii) an $11.4 million increase in propylene fractionation fee revenues and (iv) lower operating expenses of $13.1 million at our Mont Belvieu propylene fractionators primarily due to rescheduling of certain maintenance activities to the second quarter of 2015.

Comparison of 2013 with 2012. Gross operating margin from our propylene fractionation and related activities for 2013 decreased $58.4 million when compared to 2012 primarily due to lower propylene sales margins in 2013, which accounted for a $62.7 million decrease, partially offset by higher transportation fees on North Dean Pipeline, which accounted for a $6.2 million increase.

Butane isomerization and deisobutanizer operations

Comparison of 2014 with 2013. Gross operating margin from our butane isomerization and deisobutanizer ("DIB") operations decreased an aggregate $23.9 million for 2014 when compared to 2013. The year-to-year decrease is primarily due to higher maintenance costs incurred during 2014, which accounted for a $14.4 million decrease, and lower by-product sales revenues primarily due to lower commodity prices, which accounted for an $11.5 million decrease.

Comparison of 2013 with 2012. Gross operating margin from these operations increased an aggregate $3.4 million for 2013 when compared to 2012 primarily due to the addition of a new standalone DIB unit at our Mont Belvieu facility in March 2013, which accounted for $5.6 million of gross operating margin for the year and 27 MBPD of additional processing volumes.

Octane enhancement and HPIB plant operations

Comparison of 2014 with 2013. Gross operating margin from our octane enhancement facility and high purity isobutylene ("HPIB") plant decreased a net $32.3 million for 2014 when compared to 2013. The year-to-year decrease in gross operating margin is primarily due to an extended period of unscheduled maintenance at the octane enhancement facility during the first quarter of 2014 and reduced operating rates for the remainder of 2014. Production volumes at our octane enhancement facility averaged 15 MBPD in 2014 compared to 18 MBPD in 2013.

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Comparison of 2013 with 2012. Gross operating margin from our octane enhancement and HPIB plant operations increased a combined $53.8 million for 2013 when compared to 2012. Our octane enhancement facility experienced extended periods of downtime for maintenance during 2012, which negatively impacted the facility's operating results for that year. The $53.8 million increase in gross operating margin for 2013 is primarily due to higher sales volumes, which accounted for a $40.0 million increase, and higher sales margins, which accounted for a $29.0 million increase, partially offset by higher operating costs, which accounted for a $16.8 million decrease.

Refined products pipelines and related activities

Comparison of 2014 with 2013. Gross operating margin from our refined products pipelines and related marketing activities for 2014 increased $22.1 million when compared to 2013. Gross operating margin from our TE Products Pipeline and related refined products terminals increased $6.8 million year-to-year primarily due to lower pipeline integrity and other maintenance expenses of $13.1 million and higher transportation tariffs and other fees of $12.2 million, partially offset by a $16.6 million benefit recorded in 2013 related to reductions in a provision for future pipeline capacity obligations on a third party pipeline. Overall, transportation volumes for the TE Products Pipeline increased a net 48 MBPD year-to-year primarily due to higher intrastate shipments of petrochemicals and refined products in southeast Texas, which accounted for a combined 64 MBPD increase, partially offset by lower interstate transportation volumes for refined products and NGLs of 16 MBPD. Interstate components of the TE Products Pipeline were removed from service during 2013 and repurposed to accommodate the southbound delivery of ethane on our ATEX pipeline, which commenced operations in January 2014. Equity earnings from our investment in Centennial Pipeline LLC ("Centennial") increased $9.3 million year-to-year primarily due to Centennial's recognition in 2014 of previously deferred revenues.

Gross operating margin from our refined products marketing activities decreased $10.3 million year-to-year primarily due to lower sales margins. In May 2014, we commenced loading operations at our Beaumont Refined Products Export Terminal, which is located on the Neches River in Southeast Texas and can load cargoes of refined products at rates up to 15,000 barrels per hour. Gross operating margin from this export terminal was $8.9 million for 2014. Gross operating margin from our Beaumont West Terminal was $7.4 million for the fourth quarter of 2014.

Comparison of 2013 with 2012. Gross operating margin from our refined products pipelines and related marketing activities for 2013 increased $74.7 million when compared to 2012 primarily due to improved results from our TE Products Pipeline and refined products terminals and related marketing activities. Gross operating margin from our TE Products Pipeline increased a net $24.7 million year-to-year primarily due to higher transportation fees, which accounted for a $52.3 million increase, partially offset by a $28.0 million decrease in gross operating margin attributable to lower refined products interstate transportation volumes. The higher transportation fees year-to-year include a $24.3 million benefit recognized in connection with the settlement of a rate case with certain shippers during the second quarter of 2013. Gross operating margin from our refined products terminals increased $27.8 million year-to-year primarily due to a $16.6 million benefit attributable to reductions in a provision for future pipeline capacity obligations recorded in the first quarter of 2013. Results from our refined products marketing activities increased $21.8 million year-to-year primarily due to higher sales margins, which accounted for a $15.7 million increase, and higher sales volumes, which accounted for a $6.1 million increase.

Marine transportation and other

Comparison of 2014 with 2013. Gross operating margin from our marine transportation and other segment services for 2014 decreased $3.5 million when compared to 2013 primarily due to higher operating expenses.

Comparison of 2013 with 2012. Gross operating margin from our marine transportation and other segment services for 2013 decreased $27.5 million when compared to 2012. Results attributable to our marine transportation business for 2012 included a $24.0 million gain recorded in connection with a legal settlement.

Liquidity and Capital Resources

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facilities. Based on current market conditions (as of the filing date of this annual 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 also 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. After taking into account the aggregate sale price of common units sold under our at-the-market program through February 1, 2015, we have the capacity to issue additional common units under this program up to an aggregate sales price of $1.17 billion.

Consolidated Debt

The following table presents scheduled maturities of our consolidated debt obligations outstanding at December 31, 2014 for the years indicated (dollars in millions):

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

We expect to refinance the current maturities of our consolidated debt obligations at or prior to their maturity. The following information describes significant transactions that affected our consolidated debt obligations during the year ended December 31, 2014:

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

In October 2014, EPO issued $800 million in principal amount of 2.55% senior notes due October 2019 ("Senior Notes LL"), $1.15 billion in principal amount of 3.75% senior notes due February 2025 ("Senior Notes MM") and $400 million in principal amount of 4.95% senior notes due October 2054 ("Senior Notes NN"). EPO also issued an additional $400 million in principal amount of its 4.85% Senior Notes II due March 2044. Net proceeds from the issuance of these senior notes were used as follows: (i) to repay debt principal amounts outstanding under EPO's $1.5 Billion 364-Day Credit Agreement (as discussed below) and commercial paper program (both of which were used to partially fund the cash consideration paid in Step 1 of the Oiltanking acquisition (see "Significant Recent Developments" within this Part II, Item 7)), (ii) to repay $650 million in principal amount of Senior Notes G that matured in October 2014, 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 indentures 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.

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

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

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

Issuance of Common Units

The following table summarizes the issuance of Enterprise common units during the years indicated in connection with underwritten equity offerings, the at-the-market program, and quarterly DRIP and employee unit purchase plan ("EUPP") (dollars in millions, number of units issued as shown):

	Number of Common Units Issued		Net Cash Proceeds Received
Year Ended December 31, 2012:
Common units issued in connection with underwritten offering		18,400,000	$	473.3
Common units issued in connection with at-the-market program (1)		7,957,090		203.8
Common units issued in connection with DRIP and EUPP		5,629,320		139.7
Total		31,986,410	$	816.8

Year Ended December 31, 2013:
Common units issued in connection with underwritten offerings		36,800,000	$	1,039.6
Common units issued in connection with at-the-market program		15,249,378		456.3
Common units issued in connection with DRIP and EUPP		10,308,254		296.1
Total		62,357,632	$	1,792.0

Year Ended December 31, 2014:
Common units issued in connection with at-the-market program		1,590,334	$	57.7
Common units issued in connection with DRIP and EUPP		9,754,227		331.1
Total		11,344,561	$	388.8

(1) The sale of common units under the at-the-market program was initiated during the third quarter of 2012.

On October 1, 2014, in order to fund the equity consideration paid in Step 1 of the Oiltanking acquisition, we issued 54,807,352 common units to OTA. Pursuant to a Registration Rights Agreement, we granted OTA registration rights with respect to these common units. On February 13, 2015, we issued an additional 36,827,557 common units to the public unitholders of Oiltanking as a result of completing the Oiltanking Merger. See "Significant Recent Developments" within this Part II, Item 7 for additional information regarding the acquisition of Oiltanking.

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The following information describes significant transactions that affected our partners' equity accounts during the year ended December 31, 2014:

At-the-market program. During the year ended December 31, 2014, we issued 1,590,334 common units under this program for aggregate gross proceeds of $58.3 million. After taking into account applicable costs, these transactions resulted in net cash proceeds of $57.7 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 our DRIP. The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional new common units. We issued a total of 9,480,407 common units under our DRIP during 2014, which generated net cash proceeds of $321.3 million. Affiliates of privately held EPCO reinvested $100.0 million under the DRIP in 2014, resulting in the issuance of 2,946,241 common units (this amount being a component of the total common units issued under the DRIP in 2014). After taking into account the number of common units issued under the DRIP through December 31, 2014, we have the capacity to issue an additional 27,481,349 common units under this plan.

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 EUPP. We issued 273,820 common units under our EUPP during 2014, which generated net cash proceeds of $9.8 million. After taking into account the number of common units issued under the EUPP through December 31, 2014, we may issue an additional 7,153,068 common units under this plan.

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

For additional information regarding our issuance of common units and related registration statements, see Note 13 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Two-for-One Split of Limited Partner Units

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

Credit Ratings

As of March 2, 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.

Designated Units Issued in Connection with Holdings Merger

In November 2010, we completed the merger of Enterprise GP Holdings L.P. with one of our wholly owned subsidiaries (the "Holdings Merger"). In connection with the Holdings Merger, a privately held affiliate of EPCO agreed to temporarily waive the regular quarterly cash distributions it would otherwise receive from us with

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respect to a certain number of our common units it owns (the "Designated Units"). Distributions paid during the year ended December 31, 2014 excluded 45,120,000 Designated Units. Distributions to be paid, if any, during the year ended December 31, 2015 will exclude 35,380,000 Designated Units, respectively.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the years indicated (dollars in millions). For additional information regarding our cash flow amounts, please refer to the Statements of Consolidated Cash Flows included under Part II, Item 8 of this annual report.

	For the Year Ended December 31,
	2014		2013		2012
Net cash flows provided by operating activities	$	4,162.2	$	3,865.5	$	2,890.9
Cash used in investing activities	$	5,797.9	$	4,257.5	$	3,018.8
Cash provided by financing activities	$	1,653.2	$	432.8	$	124.2

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 Part I, Item 1A of this annual report.

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

Comparison of 2014 with 2013

Operating Activities. Net cash flows provided by operating activities for the year ended December 31, 2014 increased $296.7 million when compared to the year ended December 31, 2013. The increase in cash provided by operating activities was primarily due to:

§	a $183.8 million increase in cash attributable to higher partnership income in 2014 compared to 2013 (after adjusting our $226.4 million year-to-year increase in net income for changes in the non-cash items identified on our Statements of Consolidated Cash Flows); and

a $123.5 million year-to-year increase in cash distributions from unconsolidated affiliates primarily due to increased earnings from our investments in crude oil and NGL pipeline joint ventures (e.g., our Eagle Ford Crude Oil Pipeline System, Texas Express Pipeline, Seaway Pipeline and Front Range Pipeline).

For information regarding significant year-to-year changes in our consolidated net income and underlying segment results, see "Results of Operations" within this Part II, Item 7.

Investing Activities. Cash used in investing activities for the year ended December 31, 2014 increased $1.54 billion when compared to the year ended December 31, 2013 primarily due to:

§	a net $2.42 billion cash outflow in October 2014 in connection with Step 1 of the Oiltanking acquisition (see "Significant Recent Developments – Acquisition of Oiltanking Partners, L.P." under this Part II, Item 7); and

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an aggregate $135.3 million year-to-year decrease in cash proceeds from asset sales and insurance recoveries (see Note 20 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report for additional information regarding proceeds from asset sales and insurance recoveries); partially offset by

§	a $518.2 million year-to-year decrease in capital expenditures for consolidated property, plant and equipment, net of contributions in aid of construction costs (see "Capital Spending" within this Part II, Item 7 for additional information regarding our capital spending program);

a $371.7 million year-to-year decrease in cash contributions to our unconsolidated affiliates primarily due to the completion of construction of the Texas Express Pipeline, SEKCO Oil Pipeline, Front Range Pipeline and Seaway Pipeline looping project, partially offset by increased investments in the Eagle Ford Crude Oil Pipeline System; and

§	a $126.9 million year-to-year change in restricted cash requirements.

Financing Activities. Cash provided by financing activities for the year ended December 31, 2014 increased $1.22 billion when compared to the year ended December 31, 2013 primarily due to:

a $2.85 billion year-to-year increase in net borrowings under our consolidated debt agreements. EPO issued $4.75 billion and repaid $1.15 billion in principal amount of senior notes in 2014, compared to the issuance of $2.25 billion and repayment of $1.2 billion in principal amount of senior notes in 2013. In addition, net cash inflows attributable to the issuance of short-term notes under EPO's commercial paper program and net borrowings under EPO's revolving credit facilities increased an aggregate of $303.4 million year-to-year; and

§	a $196.4 million year-to-year change related to the monetization of interest rate derivative instruments. A $27.6 million gain was recorded in 2014 compared to a $168.8 million loss in 2013; partially offset by

a $1.4 billion year-to-year decrease in net cash proceeds from the issuance of common units. We issued an aggregate 11,344,561 common units in connection with our DRIP, EUPP and at-the-market program in 2014, which generated $388.8 million of net cash proceeds. This compares to an aggregate 62,357,632 common units we issued in connection with an underwritten offering and our DRIP, EUPP and at-the-market program in 2013, which collectively generated $1.79 billion of net cash proceeds;

§	a $237.8 million year-to-year increase in cash distributions paid to limited partners in 2014 when compared to 2013. 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; and

§	a $111.4 million year-to-year decrease in cash contributions from noncontrolling interests primarily due to contributions we received during 2013 related to a joint venture involving NGL fractionators at our complex in Mont Belvieu, Texas.

Comparison of 2013 with 2012

Operating Activities. Net cash flows provided by operating activities for the year ended December 31, 2013 increased $974.6 million when compared to the year ended December 31, 2012. The increase in cash provided by operating activities was primarily due to:

§	a $354.8 million increase in cash attributable to higher partnership income in 2013 compared to 2012 (after adjusting our $179.1 million year-to-year increase in net income for changes in the non-cash items identified on our Statements of Consolidated Cash Flows);

§	a $484.9 million year-to-year increase in cash attributable to the timing of cash receipts and disbursements related to operations; and

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§	a $134.9 million year-to-year increase in cash distributions from unconsolidated affiliates for 2013 compared to 2012 primarily due to improved results from our investments in crude oil pipeline joint ventures.

Investing Activities. Cash used in investing activities for the year ended December 31, 2013 increased $1.24 billion when compared to the year ended December 31, 2012 primarily due to:

§	an aggregate $918.2 million year-to-year decrease in cash proceeds from asset sales and insurance recoveries. Proceeds for 2012 included the $1.1 billion we received in connection with sales of common units of Energy Transfer Equity; and

§	a $484.6 million year-to-year increase in cash contributions to our unconsolidated affiliates for 2013 compared to 2012 primarily due to expansion capital expenditures for the Seaway Pipeline, Texas Express Pipeline, Front Range Pipeline and Eagle Ford Pipeline joint ventures; partially offset by

§	a $216.3 million year-to-year decrease in capital expenditures for consolidated property, plant and equipment, net of contributions in aid of construction costs.

Financing Activities. Cash provided by financing activities for the year ended December 31, 2013 increased $308.6 million when compared to the year ended December 31, 2012 primarily due to:

a $975.2 million year-to-year increase in net cash proceeds from the issuance of common units in 2013 when compared to 2012. We issued an aggregate of 62,357,632 common units in connection with two underwritten offerings, our at-the-market program and DRIP and EUPP during 2013, which collectively generated $1.79 billion of net cash proceeds. This compares to an aggregate 31,986,410 common units we issued in connection with an underwritten offering, our at-the-market program and DRIP and EUPP during 2012, which collectively generated $816.8 million of net cash proceeds;

§	a $108.8 million year-to-year increase in cash contributions from noncontrolling interests primarily due to contributions we received during 2013 related to a joint venture involving NGL fractionators at our complex in Mont Belvieu, Texas; partially offset by

a $514.5 million year-to-year decrease in net borrowings under our consolidated debt agreements. EPO issued $2.25 billion and repaid $1.2 billion in principal amount of senior notes during 2013, compared to the issuance of $2.5 billion and repayment of $1.0 billion in principal amount of senior notes during 2012. In addition, net cash inflows attributable to the issuance of short-term notes under EPO's commercial paper program were $127.2 million for 2013 compared to $346.4 million for 2012. Lastly, net repayments under EPO's $3.5 Billion Multi-Year Revolving Credit Facility were $150.0 million for 2012; and

§	a $221.7 million increase in cash distributions paid to limited partners in 2013 when compared to 2012 due to increases in both the number of distribution-bearing common units outstanding and the quarterly cash distribution rates per unit.

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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 incentive distribution rights or other equity interests.

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 Year Ended December 31,
	2014			2013			2012
Net income attributable to limited partners (1)	$	2,787.4		$	2,596.9		$	2,419.9
Adjustments to GAAP net income attributable to limited partners to derive non-GAAP distributable cash flow:
Add depreciation, amortization and accretion expenses		1,360.5			1,217.6			1,104.9
Add asset impairment charges		34.0			92.6			63.4
Subtract net gains attributable to asset sales and insurance recoveries		(102.1	)		(83.3	)		(86.4	)
Add cash proceeds from asset sales and insurance recoveries (2)		145.3			280.6			1,198.8
Add cash distributions received from unconsolidated affiliates (3)		375.1			251.6			116.7
Subtract equity in income of unconsolidated affiliates (3)		(259.5	)		(167.3	)		(64.3	)
Subtract sustaining capital expenditures (4)		(369.0	)		(291.7	)		(366.2	)
Add gains or subtract losses from monetization of interest rate derivative instruments accounted for as cash flow hedges (5)		27.6			(168.8	)		(147.8	)
Add deferred income tax expense or subtract benefit, as applicable		6.1			37.9			(66.2	)
Other, net		73.2			(15.7	)		(39.5	)
Distributable cash flow	$	4,078.6		$	3,750.4		$	4,133.3

Total cash distributions paid to limited partners with respect to period	$	2,707.6		$	2,461.9		$	2,225.8

Cumulative quarterly cash distributions per unit declared by Enterprise GP with respect to period (6)	$	1.4500		$	1.3700		$	1.2863

Total distributable cash flow retained by partnership with respect to period (7)	$	1,371.0		$	1,288.5		$	1,907.5

Distribution coverage ratio (8)		1.51x			1.52x			1.86x

(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 II, Item 7. (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 Statements of Consolidated Cash Flows, see "Cash Flows from Operating, Investing and Financing Activities" within this Part II, Item 7. (3) For information regarding our unconsolidated affiliates, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. (4) For a discussion of our capital spending activity, see "Capital Spending" within this Part II, Item 7. Sustaining capital expenditures for each period include accruals. (5) For information regarding these gains and losses, see "Interest Rate Hedging Activities" under Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. (6) See Note 13 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding our quarterly cash distributions declared with respect to the periods presented. (7) 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. (8) 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.

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For additional information regarding non-GAAP distributable cash flow, see "Other Items – Use of Non-GAAP Financial Measures" within this Part II, Item 7. 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.

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 $4.1 billion of major capital projects into service during 2014. These projects included the ATEX, Rocky Mountain expansion of our Mid-America Pipeline System, Front Range Pipeline and Seaway Pipeline looping project. We expect to complete construction and begin commercial operations of growth capital projects costing approximately $2.6 billion in 2015. These projects include various product handling projects (e.g., natural gasoline treating and degassing) at our Mont Belvieu complex.

At December 31, 2014, we had approximately $1.3 billion in purchase commitments outstanding that relate to our capital spending for property, plant and equipment. These commitments primarily relate to construction projects in Texas.

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

	For the Year Ended December 31,
	2014		2013		2012
Step 1 of Oiltanking acquisition (1)
Cash, net of $21.5 million at Oiltanking	$	2,416.8
Equity instruments (54,807,352 common units of Enterprise)		2,171.5
Capital spending for property, plant and equipment, net: (2)
Growth capital projects (3)		2,502.8	$	3,088.0	$	3,232.7
Sustaining capital projects (4)		361.2		294.2		365.8
Investments in unconsolidated affiliates		722.4		1,094.1		609.5
Other investing activities		5.8		1.0		43.1
Total capital spending	$	8,180.5	$	4,477.3	$	4,251.1

(1) For a description of the acquisition of Oiltanking, see "Significant Recent Developments" within this Part II, Item 7. (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 $28.9 million, $26.0 million and $23.4 million for the years ended December 31, 2014, 2013 and 2012, 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 capital spending for growth capital projects and investments in unconsolidated affiliates are explained in large part by increases or decreases in spending on our major growth capital projects. Fluctuations in our capital spending for sustaining capital projects are explained in large part by the timing and cost of pipeline integrity and similar projects. Our most significant growth capital expenditures for the year ended December 31,

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2014 involved projects at our Mont Belvieu complex, to expand joint venture crude oil pipelines, for the ATEX and Aegis ethane pipelines and for our LPG, ethane and refined products export terminals.

Comparison of 2014 with 2013. On October 1, 2014, we acquired the general partner and related incentive distribution rights, 15,899,802 common units and 38,899,802 subordinated units of Oiltanking from OTA. We paid total consideration of approximately $4.4 billion to OTA comprised of $2.21 billion in cash and 54,807,352 Enterprise common units for these ownership interests and rights. We also paid $228.3 million to acquire from OTA outstanding loans payable by Oiltanking or its subsidiaries. Collectively, these transactions are referred to as "Step 1" of the Oiltanking acquisition. Oiltanking owns marine terminals located on the Houston Ship Channel and at the Port of Beaumont with a total of 12 ship and barge docks and approximately 26 MMBbls of crude oil and petroleum products storage capacity. Oiltanking's marine terminal on the Houston Ship Channel is connected by pipeline to our Mont Belvieu, Texas complex and is integral to our growing LPG export, crude oil storage and octane enhancement and propylene businesses. Our ECHO facility is also connected to Oiltanking's system. For additional information regarding the acquisition of Oiltanking, see "Significant Recent Developments" within this Part II, Item 7.

Capital spending for property, plant and equipment in 2014 decreased $518.2 million when compared to 2013 primarily due to lower growth capital expenditures of $585.2 million year-to-year, which was partially offset by an increase in sustaining capital expenditures of $67.0 million year-to-year, largely attributable to increased expenditures for pipeline integrity and similar projects.

Capital spending for growth projects in the Eagle Ford Shale and at our Mont Belvieu complex decreased a combined $408.3 million year-to-year. Since 2010, expansion of midstream infrastructure in the Eagle Ford Shale region has been a key strategic focus for us. We constructed new NGL, natural gas and crude oil pipelines and the Yoakum natural gas processing plant to facilitate production growth from Eagle Ford Shale producers. Our build-out in this supply basin was substantially complete in 2013. Likewise, we completed and placed into service the seventh and eight NGL fractionators at our Mont Belvieu complex in September 2013 and November 2013, respectively.

Growth capital spending for our ATEX and Aegis ethane pipelines decreased a net $554.1 million year-to-year. Our ATEX pipeline was placed into service in January 2014. Construction on the initial phase of Aegis was completed in September 2014 with full operations expected to commence by the end of 2015.

Growth capital spending for our LPG, ethane and refined products export facilities increased $324.1 million year-to-year. The announced expansions of our LPG export terminal located on the Houston Ship Channel are expected to increase its ability to load cargoes from 7.5 MMBbls per month to approximately 16.0 MMBbls per month and are expected to be completed in two phases by the end of 2015. In April 2014, we announced plans to construct a fully refrigerated ethane export facility located on the Houston Ship Channel, which we expect to begin operations in the third quarter of 2016. In May 2014, we began loading cargoes of refined products for export at our reactivated marine terminal located in Beaumont, Texas.

Investments in unconsolidated affiliates during 2014 decreased $371.7 million when compared to 2013. Our spending on the expansion and construction of joint venture crude oil pipelines decreased a net $106.9 million. Spending related to our construction of the Texas Express Pipeline, Texas Express Gathering System and Front Range Pipeline decreased a combined $262.7 million year-to-year.

Comparison of 2013 with 2012. Capital spending on growth capital projects for 2013 decreased $144.7 million when compared to 2012. Our spending on growth capital projects in the Eagle Ford Shale region decreased $1.01 billion, partially offset by a combined $801.4 million year-to-year increase in spending on the ATEX and Aegis ethane pipelines and the Rocky Mountain expansion of our Mid-America Pipeline System. Since 2010, expansion of midstream infrastructure in the Eagle Ford Shale region has been a key strategic focus for us. We constructed new NGL, natural gas and crude oil pipelines and the Yoakum natural gas processing plant to facilitate production growth from Eagle Ford Shale producers. As noted above, the construction of midstream infrastructure in the Eagle Ford Shale region has been a key strategic focus for us since 2010, with the build-out of such assets being substantially completed during 2013.

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A majority of the capital expenditures for ATEX and the Rocky Mountain expansion of our Mid-America Pipeline System were incurred during 2013 (prior to placing these new pipeline assets into service in January 2014). Capital spending on sustaining capital projects for 2013 decreased $71.6 million when compared to 2012 primarily due to a year-to-year decrease in pipeline integrity work and similar projects associated with our Texas Intrastate System and Mid-America Pipeline System. Investments in unconsolidated affiliates for 2013 increased $484.6 million when compared to 2012 primarily due to the expansion of the Seaway Pipeline and construction of the Texas Express Pipeline, Texas Express Gathering System and Front Range Pipeline.

Capital Spending Outlook

We currently expect our total capital spending for 2015 to approximate $3.9 billion, which includes $380 million for sustaining capital expenditures. Our forecast of capital spending for 2015 is based on our announced strategic operating and growth plans (through the filing date of this annual 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 and the issuance of additional equity and debt securities. 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.

Critical Accounting Policies and Estimates

In our financial reporting processes, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses for each reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the estimation risk currently underlying our most significant financial statement items:

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

In general, depreciation is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include (i) changes in laws and regulations that limit the estimated economic life of an asset, (ii) changes in technology that render an asset obsolete, (iii) changes in expected residual values, or (iv) significant changes in the forecast life of proved reserves of applicable resource basins, if any.

At December 31, 2014 and 2013, the net carrying value of our property, plant and equipment was $29.88 billion and $26.95 billion, respectively. We recorded $1.11 billion, $1.01 billion and $900.5 million of depreciation expense for the years ended December 31, 2014, 2013 and 2012, respectively. For additional information regarding our property, plant and equipment, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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Measuring Recoverability of Long-Lived Assets and Fair Value of Equity Method Investments

Long-lived assets, which include property, plant and equipment and intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes might be production declines that are not replaced by new discoveries or long-term decreases in the demand or price of natural gas, NGLs, crude oil or refined products. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. Estimates of undiscounted cash flows are based on a number of assumptions including anticipated operating margins and volumes; estimated useful life of the asset or asset group; and estimated residual values. If the carrying value of a long-lived asset is not recoverable, an impairment charge would be recorded for the excess of a long-lived asset's carrying value over its estimated fair value, which is derived from an analysis of the asset's estimated future cash flows, the market value of similar assets and replacement cost of the asset less any applicable depreciation or amortization. In addition, fair value estimates also include usage of probabilities for a range of possible outcomes.

An equity method investment is evaluated for impairment whenever events or changes in circumstances indicate that there is a possible permanent loss in value of the investment (i.e., other than a temporary decline). Examples of such events include sustained operating losses of the investee or long-term negative changes in the investee's industry. When evidence of a loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party sales and discounted estimated cash flow models. Estimates of discounted cash flows are based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful life of the investment's underlying assets.

A significant change in the assumptions we use to measure recoverability of long-lived assets and fair value of equity method investments could result in our recording a non-cash impairment charge. Any such write-down of the value of such assets would increase operating costs and expenses at that time.

During 2014, 2013 and 2012, we recognized non-cash asset impairment charges related to long-lived assets of $34.0 million, $92.6 million and $63.4 million, respectively, which are a component of operating costs and expenses. For additional information regarding these impairment charges, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

During 2013, we recorded a $4.8 million non-cash impairment charge related to our equity investment in Neptune. There were no impairment charges in 2014 or 2012 related to our equity method investments. For additional information regarding our equity method investments, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Amortization Methods and Estimated Useful Lives of Customer Relationships

and Contract-Based Intangible Assets

The specific, identifiable intangible assets of a business depend largely upon the nature of its operations and include items such as customer relationships and contracts. The method used to value such assets depends on a number of factors, including the nature of the asset and the economic returns it is expected to generate.

Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations and asset purchases whereby (i) we acquired information about or access to customers and now have the ability to provide services to them and (ii) the customers now have the ability to make direct contact with us. Customer relationships may arise from contractual arrangements (such as service contracts) and through means other than contracts, such as through regular contact by sales or service representatives. The value we assign to customer relationships is amortized to earnings using methods that closely resemble the pattern in which the economic benefits will be consumed (i.e., the manner in which the intangible asset is expected to contribute directly or indirectly to our cash flows). For example, the amortization periods for certain of our customer relationship intangible assets are limited by the estimated finite

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economic life of the associated hydrocarbon resource basins. In this context, our estimate of the useful life of each resource basin is predicated on a number of factors, including reserve estimates and the economic viability of production and exploration activities.

Contract-based intangible assets represent specific commercial rights we own arising from discrete contractual agreements, such as the long-term rights we possess under the Shell natural gas processing agreement and the Jonah natural gas transportation contracts. A contract-based intangible asset with a finite life is amortized over its estimated economic life, which is the period over which the asset is expected to contribute directly or indirectly to our cash flows. Our estimates of the economic life of contract-based intangible assets are based on a number of factors, including (i) the expected useful life of the related tangible assets (e.g., a fractionation facility, pipeline or other asset), (ii) any legal or regulatory developments that would impact such contractual rights and (iii) any contractual provisions that enable us to renew or extend such arrangements.

If our assumptions regarding the estimated economic life of an intangible asset were to change, then the amortization period for such asset would be adjusted accordingly. Changes in the estimated useful life of an intangible asset would impact operating costs and expenses prospectively from the date of change. If we determine that an intangible asset's unamortized cost is not recoverable due to impairment, we would be required to reduce the asset's carrying value to its estimated fair value through the recording of a non-cash impairment charge. Any such write-down of the value of an intangible asset would increase operating costs and expenses at that time.

At December 31, 2014 and 2013, the carrying value of our customer relationship and contract-based intangible asset portfolio was $2.84 billion and $1.46 billion, respectively. The carrying value of this portfolio increased $1.49 billion in connection with the customer relationship and contract-based intangible assets we acquired in connection with the acquisition of Oiltanking. We recorded $110.6 million, $105.6 million and $125.7 million of amortization expense attributable to intangible assets for the years ended December 31, 2014, 2013 and 2012, respectively. For additional information regarding our intangible assets, see Note 11 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Methods We Employ to Measure the Fair Value of Goodwill and Related Assets

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; however, it is subject to annual impairment testing at the end of each fiscal year, and more frequently, if circumstances indicate it is probable that the fair value of goodwill is below its carrying amount. Goodwill impairment testing involves determining the fair value of the associated reporting unit. The fair value of a reporting unit is based on assumptions regarding the future economic prospects of the businesses that make up the reporting unit. Such assumptions include (i) discrete financial forecasts for the associated businesses, which, in turn, rely on management's estimates of operating margins, throughput volumes and similar inputs; (ii) long-term growth rates for cash flows beyond discrete forecast periods; and (iii) appropriate discount rates. If the fair value of a reporting unit (including its inherent goodwill) is less than its carrying value, a non-cash charge to operating costs and expenses is required to reduce the carrying value of goodwill to its implied fair value. At December 31, 2014 and 2013, the carrying value of our goodwill was $4.2 billion and $2.08 billion, respectively.

In October 2014, we recorded $2.12 billion of goodwill in connection with Step 1 of our acquisition of Oiltanking. In addition, we recorded an indefinite-life intangible asset valued at $1.46 billion in connection with the acquisition of Oiltanking's incentive distribution rights. The incentive distribution rights represented contractual rights to the incentive cash distributions to be paid by Oiltanking to its general partner. Immediately after completion of the Oiltanking Merger in February 2015, the incentive distribution rights were cancelled in exchange for limited partner interests in Oiltanking, and the carrying value of this intangible asset was reclassified to goodwill. While the incentive distribution rights were outstanding, this intangible asset was not subject to amortization, but was subject to periodic testing for recoverability in a manner similar to goodwill. We attribute the goodwill resulting from the acquisition of Oiltanking to our ability to leverage the acquired business with our existing asset base to create future business opportunities. These opportunities include the marketing of NGLs, crude oil and condensate, and refined products.

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We did not record any goodwill impairment charges in 2014, 2013 or 2012. Based on our most recent goodwill impairment test at December 31, 2014, each reporting unit's fair value was substantially in excess of its carrying value (i.e., by at least 10%). For additional information regarding our goodwill, see Note 11 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Revenue Recognition Policies and Use of Estimates for Revenues and Expenses

In general, we recognize revenue from customers when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists; (ii) delivery has occurred or services have been rendered; (iii) the buyer's price is fixed or determinable; and (iv) collectibility is reasonably assured. We record revenue when sales contracts are settled (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). We record any necessary allowance for doubtful accounts as required by our established policy. For additional information regarding our revenue recognition policies, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our use of estimates for certain revenues and expenses has increased as a result of SEC regulations that require us to submit financial information on accelerated time frames. Such estimates are necessary due to the time required to compile actual billing information and receive third party data needed to record transactions for financial reporting purposes. One example of our use of estimates is the accrual of an estimate of processing plant revenue and the cost of natural gas for a given month (prior to receiving actual customer and vendor-related plant operating information for a specific period). These estimates reverse in the following month and are offset by the corresponding actual customer billing and vendor-invoiced amounts. Accordingly, we include one month of certain estimated data in our results of operations. Such estimates are generally based on actual volume and price data through the first part of the month and estimated for the remainder of the month.

Changes in facts and circumstances may result in revised estimates and could affect our reported financial statements and accompanying disclosures. If the assumptions underlying our revenue and expense estimates prove to be substantially incorrect, it could result in material adjustments in results of operations between periods. We review our estimates based on currently available information.

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 14 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report.

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

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

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

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

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The following table summarizes the deferred revenue amounts attributable to shipper make-up rights included in gross operating margin for the periods indicated (dollars in millions):

	For the Year Ended December 31,
	2014		2013
NGL Pipelines & Services:
Texas Express Pipeline (1,2)	$	3.2	$	1.3
Front Range Pipeline (1,2)		5.5		--
ATEX (3)		55.2		--
Aegis Ethane Pipeline		0.9		--
Total segment gross operating margin		64.8		1.3
Onshore Crude Oil Pipelines & Services:
Seaway Pipeline (1,4)		19.8		3.1
Total segment gross operating margin		19.8		3.1
Total amount included in overall gross operating margin	$	84.6	$	4.4

(1) Amounts presented represent our ownership share in these unconsolidated affiliates as follows: Texas Express Pipeline, 35%; Front Range Pipeline, 33.3%; and Seaway Pipeline, 50%. (2) Shippers on the Texas Express Pipeline and Front Range Pipeline have experienced periods where transportation volumes have been less than committed volumes due to ethane rejection in the supply basins served by these pipelines. (3) Shipper transportation volumes on ATEX have been negatively impacted by changes in producer drilling programs, including the timing of new production well start-ups in the Marcellus and Utica Shale developments. (4) Shippers on Seaway's Longhaul System have experienced periods where transportation volumes have been less than committed volumes due to lower regional crude oil price spreads between the Cushing hub and Gulf Coast destination markets. In general, as price spreads decrease, there is less incentive to ship crude oil to the Gulf Coast. The primary reason for the lower spreads is a narrowing of the price differential between WTI and Brent prices.

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 Year Ended December 31,
	2014			2013			2012
Distributable cash flow	$	4,078.6		$	3,750.4		$	4,133.3
Adjustments to reconcile distributable cash flow to net cash flows provided by operating activities:
Add sustaining capital expenditures reflected in distributable cash flow		369.0			291.7			366.2
Subtract cash proceeds from asset sales and insurance recoveries reflected in distributable cash flow		(145.3	)		(280.6	)		(1,198.8	)
Add losses or subtract gains from monetization of interest rate derivative instruments accounted for as cash flow hedges		(27.6	)		168.8			147.8
Net effect of changes in operating accounts not reflected in distributable cash flow		(108.2	)		(97.6	)		(582.5	)
Other, net		(4.3	)		32.8			24.9
Net cash flows provided by operating activities	$	4,162.2		$	3,865.5		$	2,890.9

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Contractual Obligations

The following table summarizes our significant contractual obligations at December 31, 2014 (dollars in millions):

			Payment or Settlement due by Period
			Less than		1-3		4-5		More than
Contractual Obligations	Total		1 year		years		years		5 years
Scheduled maturities of debt obligations (1)	$	21,389.2	$	2,206.5	$	1,550.0	$	1,850.0	$	15,782.7
Estimated cash payments for interest (2)	$	21,303.9	$	1,005.6	$	1,921.6	$	1,746.4	$	16,630.3
Operating lease obligations (3)	$	542.7	$	60.5	$	118.4	$	91.2	$	272.6
Purchase obligations: (4)
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	2,139.7	$	637.5	$	834.6	$	490.6	$	177.0
NGLs	$	487.0	$	391.1	$	52.7	$	43.2	$	--
Crude oil	$	2,425.2	$	2,279.1	$	74.7	$	71.4	$	--
Petrochemicals and refined products	$	1,499.3	$	956.7	$	542.6	$	--	$	--
Other	$	71.8	$	38.1	$	16.1	$	8.4	$	9.2
Underlying major volume commitments:
Natural gas (in TBtus)		879		255		347		210		67
NGLs (in MMBbls)		30		17		7		6		--
Crude oil (in MMBbls)		41		38		2		1		--
Petrochemicals and refined products (in MMBbls)		23		15		8		--		--
Service payment commitments (5)	$	850.8	$	200.6	$	336.3	$	152.8	$	161.1
Capital expenditure commitments (6)	$	1,299.8	$	1,299.8	$	--	$	--	$	--
Other long-term liabilities (7)	$	310.8	$	--	$	10.7	$	8.7	$	291.4
Total	$	52,320.2	$	9,075.5	$	5,457.7	$	4,462.7	$	33,324.3

(1) Represents scheduled future maturities of our consolidated debt principal obligations. For information regarding our consolidated debt obligations, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. (2) Estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2014, the contractually scheduled maturities of such balances, and the applicable fixed or variable interest rates paid during 2014. With respect to our variable-rate debt obligations, we applied the weighted-average interest rate paid during 2014 to determine the estimated cash payments. See Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for the weighted-average variable interest rate charged in 2014 under our revolving credit facility. Our estimated cash payments for interest are significantly influenced by the long-term maturities of our junior subordinated notes (due August 2066 through January 2068). Our estimated cash payments for interest with respect to each junior subordinated note are based on the current fixed interest rate for each note applied to the entire remaining term through the respective maturity date. (3) Primarily represents leases of underground salt dome caverns for the storage of natural gas and NGLs, office space with affiliates of EPCO and land held pursuant to right-of-way agreements. (4) Represents enforceable and legally binding agreements to purchase goods or services as of December 31, 2014. The estimated payment obligations are based on contractual prices in effect at December 31, 2014 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. (5) Primarily represents our unconditional payment obligations under firm pipeline transportation contracts. (6) Represents unconditional payment obligations for services to be rendered or products to be delivered in connection with our capital spending program, including our share of the capital spending of our unconsolidated affiliates. (7) As reflected on our consolidated balance sheet at December 31, 2014, Other long-term liabilities primarily represent the Liquidity Option Agreement and the noncurrent portion of asset retirement obligations and deferred revenues.

For additional information regarding our significant contractual obligations, see Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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Insurance Matters

We participate as a named insured in EPCO's insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material impact on our financial position, results of operations and cash flows.

In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of our common units.

Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. EPCO's deductibles currently range from $5.0 million to $60.0 million depending on the nature of the loss (windstorm or non-windstorm) and the assets involved (onshore or offshore).

We received $95.0 million, $15.0 million and $30.0 million of nonrefundable insurance proceeds during the years ended December 31, 2014, 2013 and 2012, respectively, attributable to property damage claims we filed in connection with a February 2011 NGL release and fire at the West Storage location of our Mont Belvieu, Texas underground storage facility. Operating income for the years ended December 31, 2014, 2013 and 2012 includes $95.0 million, $15.0 million and $30.0 million of gains, respectively, related to these insurance recoveries. The amounts we received during the first quarter of 2014 represent the final payments on this property damage claim.

For additional information regarding insurance matters, see Note 19 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Regulation

For information regarding the impact of federal, state or local regulatory measures on our business, see "Regulatory Matters" included under Part I, Item 1 and 2 of this annual report.

Recent Accounting Developments

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

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

identify the contract;

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identify the performance obligations in the contract;

determine the transaction price;

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

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

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

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

Item 7A. 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.

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 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding our derivative instruments and hedging activities.

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Commodity Hedging Activities

The prices of natural gas, NGLs, crude oil, refined products and petrochemical products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps, basis swaps and option contracts.

The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2014 (volume measures as noted):

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

(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2015, October 2015 and March 2018, respectively.
(3) Forecasted sales of NGL volumes under natural gas processing exclude 0.1 MMBbls of additional hedges executed under contracts that have been designated as normal sales agreements.
(4) Current volumes include and 35.2 Bcf of physical derivative instruments that are predominantly priced at a marked-based index plus a premium or minus a discount related to location differences.
(5) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.

Our predominant commodity hedging strategies in 2014 and continuing into early 2015 consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities and (ii) hedging the fair value of commodity products held in inventory. The objective of our hedging program involving anticipated future commodity purchases and sales is to hedge the margins of certain transportation, storage and blending, processing and fractionation activities by locking in purchases and sales prices through the use of forward contracts and derivative instruments. The objective of our hedging program for inventory is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of forward contracts and derivative instruments.

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

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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, 2013				December 31, 2014			January 31, 2015
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(1.3	)		$	5.8		$	1.4
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(6.7	)			2.4			(1.0	)
Fair value assuming 10% decrease in underlying commodity prices	Asset			4.1				9.2			3.7

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, 2013				December 31, 2014			January 31, 2015
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(20.7	)		$	57.8		$	23.0
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(69.8	)			47.5			13.3
Fair value assuming 10% decrease in underlying commodity prices	Asset			28.5				68.2			32.8

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, 2013				December 31, 2014			January 31, 2015
Fair value assuming no change in underlying commodity prices	Asset		$	8.2			$	15.6		$	22.2
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(9.8	)			6.5			9.3
Fair value assuming 10% decrease in underlying commodity prices	Asset			26.1				24.7			35.0

Product Purchase Commitments

We have long and short-term purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products. The purchase prices that we are obligated to pay under these contracts are based on market prices at the time we take delivery of the volumes. For additional information regarding these commitments, see Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Interest Rate Hedging Activities

We may utilize interest rate swaps, forward starting swaps and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain debt agreements. This strategy has been a component in controlling our overall cost of capital associated with such borrowings. The composition of our derivative instrument portfolios may change from period-to-period depending on our interest rate hedging requirements. At December 31, 2014 and March 2, 2015, we did not have any interest rate hedging derivative instruments outstanding.

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

As a result of market conditions in early October 2014, we elected to terminate all of our outstanding interest rate swaps. We terminated 10 fixed-to-floating swaps having an aggregate notional value of $750 million, which resulted in cash gains totaling $17.6 million. In addition, we terminated 16 fixed-to-floating swaps having a total notional value of $800 million entered into in connection with the issuance of Senior Notes LL in October 2014. The early termination of these 16 swaps resulted in cash gains totaling $10.0 million. Since both groups of swaps were accounted for as fair value hedges, the aggregate $27.6 million of gains will be carried as a component of long-term debt and be amortized into earnings (as a decrease in interest expense) using the effective interest method over the remaining life of the associated debt obligations. The $17.6 million gain will be amortized through

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January 2016 and the $10.0 million gain will be amortized through October 2019.

Item 8. Financial Statements and Supplementary Data

Our audited consolidated financial statements begin on page F-1 of this annual report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

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

As a result of our acquisition of a controlling interest in Oiltanking on October 1, 2014, the Company is evaluating and implementing changes to processes, policies and other components of its internal control over financial reporting with respect to the consolidation of Oiltanking's operations into the Company's financial statements. Management continues to be engaged in efforts to evaluate the effectiveness of our internal control procedures and the design of those control procedures relating to Oiltanking. Due to the recent nature of this business combination, we have excluded Oiltanking from the scope of management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2014.

Apart from internal control considerations related to Oiltanking, 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 fourth quarter of 2014, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Certifications

The required certifications of Mr. Creel and Mr. Fowler under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are included as exhibits to this annual report (see Exhibits 31 and 32 included under Part IV, Item 15 of this annual report).

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MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING AS OF DECEMBER 31, 2014

The management of Enterprise Products Partners L.P. and its consolidated subsidiaries, including its chief executive officer and chief financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal control system was designed to provide reasonable assurance to the management of Enterprise Products Partners L.P. and the Board of Directors of its general partner regarding the preparation and fair presentation of Enterprise Products Partners L.P.'s published financial statements.

Our management assessed the effectiveness of Enterprise Products Partners L.P.'s internal control over financial reporting as of December 31, 2014. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control—Integrated Framework (2013). This assessment included a review of the design and operating effectiveness of internal controls over financial reporting as well as the safeguarding of assets. Based on our assessment, we believe that, as of December 31, 2014, Enterprise Products Partners L.P.'s internal control over financial reporting is effective based on those criteria.

Our Audit and Conflicts Committee is comprised of independent directors who are not officers or employees of our general partner. This committee meets regularly with members of management, internal audit staff and representatives of Deloitte & Touche LLP, which is our independent registered public accounting firm, to discuss the adequacy of Enterprise Products Partners L.P.'s internal controls over financial reporting, consolidated financial statements and the nature, extent and results of the audit effort. Management reviews all of Enterprise Products Partners L.P.'s significant accounting policies and assumptions affecting its results of operations with the Audit and Conflicts Committee. Both the independent registered public accounting firm and our internal auditors have direct access to the Audit and Conflicts Committee without the presence of management.

We acquired a controlling financial interest in Oiltanking on October 1, 2014. Due to the recent nature of this business combination, it was not practical from a timing or resource standpoint for us to conduct a thorough assessment of Oiltanking's internal control over financial reporting prior to December 31, 2014. As a result, we excluded Oiltanking from the scope of our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2014. We are in the process of implementing our internal control structure over the operations of Oiltanking and expect that this effort will be completed in 2015. Oiltanking accounted for less than 1% of our consolidated revenues for the year ended December 31, 2014 and 13% of our total consolidated assets at December 31, 2014.

Deloitte & Touche LLP has issued its attestation report regarding our internal control over financial reporting. That report is included within this Item 9A (see "Report of Independent Registered Public Accounting Firm").

Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this annual report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in their respective capacities indicated below on March 2, 2015.

/s/ Michael A. Creel		/s/ W. Randall Fowler
Name:	Michael A. Creel	Name:	W. Randall Fowler
Title:	Chief Executive Officer of our general	Title:	Chief Financial Officer of our general
	partner, Enterprise Products Holdings LLC		partner, Enterprise Products Holdings LLC

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Enterprise Products Holdings LLC and the

Unitholders of Enterprise Products Partners L.P.

Houston, Texas

We have audited the internal control over financial reporting of Enterprise Products Partners L.P. and subsidiaries (the "Company") as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management's Annual Report on Internal Controls Over Financial Reporting as of December 31, 2014, management excluded from its assessment the internal control over financial reporting of Oiltanking Partners, L.P., a controlling interest in which was acquired on October 1, 2014 and whose financial statements constitute less than 1% of revenues and 13% of total assets of the consolidated financial statement amounts as of and for the year ended December 31, 2014. Accordingly, our audit did not include the internal control over financial reporting at Oiltanking Partners, L.P. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting as of December 31, 2014. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's Board of Directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

(continued on next page)

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We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the related statements of consolidated operations, comprehensive income, cash flows, and equity as of and for the year ended December 31, 2014 of the Company and our report dated March 2, 2015 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 2, 2015

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Partnership Governance.

Partnership Management

On April 24, 2014, Dan Duncan LLC, the sole member of Enterprise GP, re-elected the following individuals to the Board of Directors (the "Board") of Enterprise GP: Thurmon M. Andress, E. William Barnett, Mr. Creel, Mr. Fowler, Charles E. McMahen, Richard S. Snell, A. James Teague and Ms. Williams. In addition, a new director, James T. Hackett, was elected to join the Board. The following individuals (who served as directors prior to April 24, 2014) were not re-elected to the Board: Mr. Bachmann; Larry J. Casey, Dr. Cunningham, Rex C. Ross and Edwin E. Smith.

After giving effect to the election of the new Board on April 24, 2014, Mr. Casey and Mr. Smith were appointed as "advisory directors." O.S. Andras will also continue to serve as a "honorary director." Service as an advisory or honorary director does not confer any of the rights, obligations, liabilities or responsibilities of a director of Enterprise GP (including any power or authority to vote on any matters as a director).

On October 1, 2014, Dan Duncan LLC elected Dr. F. Christian Flach to the Board in connection with our acquisition of ownership interests in Oiltanking and its general partner from affiliates of M&B. M&B is entitled to designate a nominee for election to the Board (the "M&B Designee") as long as M&B and its affiliates beneficially own at least 27,403,676 of the Enterprise common units issued to M&B and its affiliates in connection with the Oiltanking acquisition. Dr. Flach serves on the Board as the current M&B Designee. In the event that the M&B Designee becomes unable or unwilling to, or for another reason ceases to, serve as a member of the Board while M&B is entitled to maintain the M&B Designee, M&B may designate another person reasonably acceptable to the Board as a replacement.

As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for our management, administrative or operating functions. Pursuant to the ASA, these roles are performed by employees of EPCO, which are under the direction of the Board and executive officers of Enterprise GP. The executive officers of Enterprise GP are elected for one-year terms and may be removed, with or without cause, only by the Board. Our unitholders do not elect the officers or directors of Enterprise GP. The DD LLC Trustees, through their control of Enterprise GP, have the ability to elect, remove and replace at any time, all of the officers and directors of our general partner. Each member of the Board of Enterprise GP serves until such member's death, resignation or removal. The employees of EPCO who served as directors of our general partner during 2014 were Ms. Williams and Messrs. Bachmann, Creel, Cunningham, Fowler and Teague.

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Notwithstanding any contractual limitation on its obligations or duties, Enterprise GP is liable for all debts we incur (to the extent not paid by us), except to the extent that such indebtedness or other obligations are non-recourse to Enterprise GP. Whenever possible, Enterprise GP intends to make any such indebtedness or other obligations non-recourse to itself.

Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events, any director or officer, or while serving as director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events, any person who is or was an employee (other than an officer) or agent of our general partner.

Office of the Chairman

In February 2013, the Board approved the creation of a management oversight group, known as the Office of the Chairman, which consists of the Chairman of the Board – Ms. Williams, CEO – Mr. Creel and Chief Operating Officer ("COO") – Mr. Teague. In her role as Chairman of the Board (a non-executive role), Ms. Williams is responsible for, among other things: (i) presiding over and setting the agendas for meetings of the Board, with due consideration for the values and business goals of Enterprise and an effective governance structure; (ii) overseeing the appropriate flow of information to the Board; (iii) acting as a liaison between the Board and senior management; and (iv) meeting regularly with the CEO and COO and other Board members to review the strategic direction of Enterprise.

In his role as CEO, Mr. Creel remains our principal executive officer and is responsible for, among other things: (i) managing the overall business and financial strategy of Enterprise; (ii) overseeing and providing strategic direction for our businesses, subject to Board approval, in the areas of finance, accounting, human resources, investor relations, risk management and information technology; and (iii) providing required certifications as principal executive officer of Enterprise regarding disclosure controls and procedures and internal control over financial reporting. In his role as COO, Mr. Teague is responsible for, among other things, managing the day-to-day operations of Enterprise and overseeing and providing strategic direction for our businesses, subject to Board approval, in the areas of operations, business development, health and safety. Each of the roles of CEO and COO report directly to the Board.

The purpose of the Office of the Chairman is for the group to serve collectively as a liaison to the Board and senior management with respect to, and to provide the Chairman, CEO and COO a venue to discuss, certain matters including: (i) our strategic direction (including business opportunities through organic growth and acquisitions); (ii) the vision, leadership and development of the management team; (iii) business goals and operational performance; and (iv) strategies to preserve our financial strength. In addition, the Office of the Chairman will assist the Board and its Governance Committee in identifying director education opportunities and in determining the size and composition of the Board and recruitment of new members. The Office of the Chairman also oversees policies that (i) reflect Enterprise's values and business goals and (ii) enhance the effectiveness of our governance structure.

Partnership Governance

We are committed to sound principles of governance. Such principles are critical for us to achieve our performance goals and maintain the trust and confidence of investors, employees, suppliers, business partners and other stakeholders.

A key element of strong governance is having independent members of the Board. Pursuant to the NYSE listing standards, a director will be considered independent if the Board determines that he or she does not have a material relationship with Enterprise GP or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with Enterprise GP or us). Based on the foregoing, the Board has affirmatively determined that Messrs. Andress, Barnett, Hackett, McMahen and Snell are independent directors under the NYSE rules.

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Because we are a limited partnership and meet the definition of a "controlled company" under the listing standards of the NYSE, we are not required to comply with certain NYSE rules. In particular, we are not required to comply with Section 303A.01 of the NYSE Listed Company Manual, which would require that the Board of our general partner be comprised of a majority of independent directors. Currently, five of the ten Board members of Enterprise GP are independent under NYSE rules; however, this composition may not always be in effect. Also, we have elected to not comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require that the Board of Enterprise GP maintain a Nominating Committee and a Compensation Committee, each consisting entirely of independent directors.

Code of Conduct and Ethics and Corporate Governance Guidelines

Enterprise GP has adopted a "Code of Conduct" that applies to its directors, officers and employees. This code sets forth our requirements for compliance with legal and ethical standards in the conduct of our business, including general business principles, legal and ethical obligations, compliance policies for specific subjects, obtaining guidance on complying with the code, the reporting of compliance issues, and discipline for violations of the code. The Code of Conduct also establishes policies applicable to our CEO, chief financial officer ("CFO"), principal accounting officer and senior financial and other managers to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications, and prompt internal reporting of violations of the code (and thus accountability for adherence to the code). Employees are required to periodically certify their understanding and compliance with the Code of Conduct.

Governance guidelines, together with applicable committee charters, provide the framework for effective governance of our partnership. The Board has adopted the "Governance Guidelines of Enterprise Products Partners," which address several matters, including qualifications for directors, responsibilities of directors, retirement of directors, the composition and responsibilities of the Audit and Conflicts Committee and the Governance Committee, the conduct and frequency of Board and committee meetings, management succession plans, director access to management and outside advisors, director compensation, director and executive officer equity ownership, director orientation and continuing education, and annual self-evaluation of the Board. The Board recognizes that effective governance is an on-going process, and thus, it will review the Governance Guidelines of Enterprise Products Partners annually or more often as deemed necessary.

Audit and Conflicts Committee

The purpose of the Board's Audit and Conflicts Committee is to address audit and conflicts-related matters. In accordance with NYSE rules and the Securities Exchange Act of 1934, the Board has named three of its members to serve on the Audit and Conflicts Committee. Members of the Audit and Conflicts Committee must have a basic understanding of finance and accounting matters and be able to read and understand fundamental financial statements, and at least one member of the Audit and Conflicts Committee shall have accounting or related financial management expertise. The current members of the Audit and Conflicts Committee are Messrs. Andress, McMahen and Snell, all of whom are independent directors, free from any relationship with us or any of our subsidiaries that would interfere with the exercise of independent judgment. The Board has affirmatively determined that Mr. McMahen satisfies the definition of "Audit Committee Financial Expert" as defined in Item 407(d)(5) of Regulation S-K promulgated by the SEC.

The primary responsibilities of the Audit and Conflicts Committee include (i) reviewing potential conflicts of interest, including related party transactions, (ii) monitoring the integrity of our financial reporting process and related systems of internal control, (iii) ensuring our legal and regulatory compliance and that of Enterprise GP, (iv) overseeing the independence and performance of our independent public accountant, (v) approving all services performed by our independent public accountant, (vi) providing for an avenue of communication among the independent public accountant, management, internal audit function and the Board, (vii) encouraging adherence to and continuous improvement of our policies, procedures and practices at all levels, (viii) reviewing areas of potential significant financial risk to our businesses and (ix) approving awards granted under long-term incentive plans.

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If the Board believes that a particular matter presents a conflict of interest and proposes a resolution, the Audit and Conflicts Committee has the authority to review such matter to determine if the proposed resolution is fair and reasonable to us. Any matters approved by the Audit and Conflicts Committee are conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by Enterprise GP or the Board of any duties they may owe us or our unitholders.

Pursuant to its formal written charter, the Audit and Conflicts Committee has the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it has direct access to our independent public accountants as well as any EPCO personnel whom it deems necessary in fulfilling its responsibilities. The Audit and Conflicts Committee has the ability to retain, at our expense, special legal, accounting or other consultants or experts it deems necessary in the performance of its duties.

Governance Committee

The primary purpose of the Governance Committee is to develop and recommend to the Board a set of governance guidelines applicable to our partnership, to review such guidelines from time to time and to oversee governance matters related to our business, including Board and Committee composition, qualifications of Board candidates, director independence, succession planning and related matters. The Governance Committee also assists in Board oversight of management's establishment and administration of our environmental, health and safety policies, procedures, programs and initiatives, and related matters. In accordance with its charter, the Governance Committee shall be composed of not less than three members, at least a majority of whom shall be independent directors. Currently, the Governance Committee is comprised of Ms. Williams and two independent directors, namely Messrs. Barnett and Hackett.

Like the Audit and Conflicts Committee, the Governance Committee has the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it has direct access to our independent public accountants as well as any EPCO personnel whom it deems necessary in fulfilling its responsibilities. In addition, the Governance Committee has the ability to retain, at our expense, special legal, accounting or other consultants or experts it deems necessary in the performance of its duties.

Investor Access to Corporate Governance Information

We provide investors access to information relating to our governance procedures and principles, including the Code of Conduct, Governance Guidelines, the Audit and Conflicts Committee and Governance Committee charters, along with other information, through our website, www.enterpriseproducts.com. You may also contact our Investor Relations department at (866) 230-0745 for printed copies of these documents free of charge.

NYSE Corporate Governance Listing Standards

On March 24, 2014, Mr. Creel, our CEO, certified to the NYSE (as required by Section 303A.12(a) of the NYSE Listed Company Manual) that he was not aware of any violation by us of the NYSE's Corporate Governance listing standards as of March 24, 2014.

Executive Sessions of Non-Management Directors

The Board holds regular executive sessions in which non-management directors meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. During such executive sessions, one director is designated as the "presiding director," who is responsible for leading and facilitating such executive sessions. Currently, the presiding director is Mr. McMahen.

In accordance with NYSE rules, we have established a toll-free, confidential telephone hotline (the "Hotline") so that interested parties may communicate with the presiding director or with all the non-management directors as a group. All calls to this Hotline are reported to the chairman of the Audit and Conflicts Committee, who is responsible for communicating any necessary information to the other non-management directors. The number of our confidential Hotline is (877) 888-0002.

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Directors and Executive Officers of Enterprise GP

The following table sets forth the name, age and position of each of the directors, excluding advisory or honorary directors, and executive officers of Enterprise GP at March 2, 2015. Each executive officer holds the same respective office shown below in the managing member of EPO.

Name	Age	Position with Enterprise GP
Randa Duncan Williams (1,2)	53	Director and Chairman of the Board
Thurmon M. Andress (3)	81	Director
E. William Barnett (2.4)	82	Director
Michael A. Creel (1,5)	61	Director and CEO
Dr. F. Christian Flach	47	Director
W. Randall Fowler (5)	58	Director, Executive Vice President and CFO
James T. Hackett (2)	60	Director
Charles E. McMahen (3,6)	75	Director
Richard S. Snell (3)	72	Director
A. James Teague (1,5)	69	Director and COO
Graham W. Bacon (5)	51	Group Senior Vice President
G. R. Cardillo (5)	57	Group Senior Vice President
Craig W. Murray (5)	67	Group Senior Vice President and General Counsel
William Ordemann (5)	55	Group Senior Vice President
Michael C. Smith (5)	43	Group Senior Vice President
Bryan F. Bulawa (5)	45	Senior Vice President and Treasurer
Michael J. Knesek (5)	60	Senior Vice President, Controller and Principal Accounting Officer

(1) Member of Office of the Chairman (2) Member of the Governance Committee (3) Member of the Audit and Conflicts Committee (4) Chairman of the Governance Committee (5) Executive officer (6) Chairman of the Audit and Conflicts Committee

The following information presents a brief history of the business experience of our directors and executive officers:

Randa Duncan Williams. Ms. Williams was elected as Chairman of the Board of Directors of Enterprise GP in February 2013 and as a director of Enterprise GP in November 2010. She also serves as a member of Enterprise GP's Governance Committee. She served as a director of Holdings GP from May 2007 to November 2010. She was elected Chairman of EPCO in May 2010, having previously served as Group Co-Chairman since 1994. Ms. Williams has served as a director of EPCO since February 1991. Prior to joining EPCO, Ms. Williams practiced law with the firms Butler & Binion and Brown, Sims, Wise & White. Ms. Williams previously served on the board of directors of Encore Bancshares from July 2007 until July 2012. She currently serves on the board of trustees for numerous charitable organizations. Ms. Williams is the daughter of the late Mr. Dan L. Duncan, Enterprise's founder.

Thurmon M. Andress. Mr. Andress was elected a director of Enterprise GP in November 2010 and serves as a member of Enterprise GP's Audit and Conflicts Committee. He served as a director of Holdings GP from November 2006 to November 2010. Mr. Andress serves as the Managing Director for Breitburn Management Company L.P. and is a former member of its Board of Directors. In 1990, he founded Andress Oil & Gas Company, serving as its President and CEO until it merged with Breitburn Energy Company L.P. in 1998. In 1982, he founded Bayou Resources, Inc. a publicly traded energy company that was sold in 1987. From 2002 through December 2009, Mr. Andress served as a member of the Board of Directors of Edge Petroleum Corp. (including its Governance and Compensation Committees). In October 2009, Edge Petroleum Corp. filed a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code and, on December 31, 2009, completed the sale of substantially all of its assets to Mariner Energy, Inc. Mr. Andress is currently a member of the National Petroleum Council and the Natural Gas Committee. He also serves on the Board of Governors of Houston for the Independent Petroleum Association of America. In 1993, Mr. Andress was inducted into All American Wildcatter's, a 100-member organization dedicated to American oil and gas explorationists and producers.

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E. William Barnett. Mr. Barnett was elected a director of Enterprise GP in November 2010 and serves as Chairman of its Governance Committee. He served as a director of EPGP from March 2005 to November 2010. Mr. Barnett practiced law with Baker Botts L.L.P. from 1958 until his retirement in 2004. In 1984, he became Managing Partner of Baker Botts L.L.P. and continued in that role for 14 years until 1998. He was Senior Counsel to the firm from 1998 until June 2004, when he retired from the firm. Mr. Barnett served as Chairman of the Board of Trustees of Rice University from 1996 to July 2005. Mr. Barnett is a Life Trustee of The University of Texas Law School Foundation and a Director Emeritus and former Chairman of the Houston Zoo, Inc. (the operating arm of the Houston Zoo). From June 2006 until May 2013, he served as a director of Westlake Chemical Corporation (a publicly traded chemical company). From October 2002 until May 2012, Mr. Barnett served as a director of GenOn Energy, Inc. (a publicly traded wholesale electricity generation company) and its predecessors. Mr. Barnett is Chairman of the Advisory Board of the Baker Institute for Public Policy at Rice University and a Director Emeritus and former Chairman of the Greater Houston Partnership. Mr. Barnett is a Trustee Emeritus of the Baylor College of Medicine.

Michael A Creel. Mr. Creel was elected CEO and a director of Enterprise GP in November 2010 and served as President of Enterprise GP from November 2010 until February 2013. He served as a director of EPGP from February 2006 to November 2010 and President and CEO of EPGP from August 2007 to November 2010. Mr. Creel served as CFO of EPGP from June 2000 to August 2007, and as an Executive Vice President of EPGP from January 2001 to August 2007. Mr. Creel, a Certified Public Accountant, also served as a Senior Vice President of EPGP from November 1999 to January 2001.

Mr. Creel previously served as a director of Holdings GP from October 2009 to May 2010 and as a director of DEP Holdings, LLC ("DEP GP"), the general partner of Duncan Energy Partners L.P., from October 2006 to May 2010. He previously served as President, CEO and a director of Holdings GP from August 2005 through August 2007. From October 2006 to August 2007, he served as Executive Vice President and CFO of DEP GP. From October 2005 through December 2009, Mr. Creel served as a director of Edge Petroleum Corporation, a publicly traded oil and natural gas exploration and production company, which filed a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code in October 2009 and, on December 31, 2009, completed the sale of substantially all of its assets to Mariner Energy, Inc.

Dr. F. Christian Flach. Dr. Flach was elected a director of Enterprise GP in October 2014 in connection with the Oiltanking acquisition as the M&B designee. He previously served as Chairman of the Board of Oiltanking GP from March 2014 to October 2014. He has served as Chief Executive Officer of M&B since 2011 and is also a Member of its Executive Board. Dr. Flach began working for M&B in May of 1996 and has served in various roles for the organization and its affiliates, including General Manager of M&B and Mabanaft, the oil trading business within M&B; lawyer for Oiltanking GmbH; Director of Corporate Affairs at Oiltanking GmbH; Director of Corporate Affairs at M&B; Director of Human Resources at M&B and Managing Director of Mabanaft.

W. Randall Fowler. Mr. Fowler was elected a director of Enterprise GP in September 2011. He was named

an Executive Vice President and the CFO of Enterprise GP in November 2010, having previously served as Executive Vice President and CFO of EPGP from August 2007 to November 2010. He also served as President and CEO of DEP GP from April 2010 until September 2011 and as Executive Vice President and CFO of DEP GP from August 2007 to April 2010. He served as a director of DEP GP from September 2006 until September 2011.

Mr. Fowler served as Senior Vice President and Treasurer of EPGP from February 2005 to August 2007 and of DEP GP from October 2006 to August 2007. Mr. Fowler also previously served as a director of EPGP and of Holdings GP from February 2006 to May 2010. Mr. Fowler also served as Senior Vice President and CFO of Holdings GP from August 2005 to August 2007. Mr. Fowler was elected Vice Chairman and CFO of EPCO in May 2010. He previously served as President and CEO of EPCO from December 2007 to May 2010 and as its CFO from April 2005 to December 2007.

Mr. Fowler, a Certified Public Accountant (inactive), joined Enterprise as Director of Investor Relations in January 1999. Mr. Fowler also serves as Chairman of the Board of the National Association of Publicly Traded Partnerships. He also serves on the Advisory Board for the College of Business at Louisiana Tech University. Mr. Fowler is on the Advisory Board of Alerian, an independent provider of master limited partnership market intelligence, which includes its benchmark Alerian MLP Index (AMZ).

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James T. Hackett. Mr. Hackett was elected as a director of Enterprise GP in April 2014 and is a member of its Governance Committee. Mr. Hackett is a partner with Riverstone Holdings LLC, a private energy investment firm. He served as Executive Chairman of the board of directors of Anadarko Petroleum Corporation ("Anadarko"), one of the world's largest independent oil and natural gas exploration and production companies, from 2012 to 2013 after serving as its CEO since 2003 and Chairman of the Board since 2006. He also served as Anadarko's President from 2003 to 2010. Mr. Hackett is a director of Cameron International Corporation and Fluor Corporation. He also serves on the board of a closed investment fund traded on the London Stock Exchange called Riverstone Energy Ltd. Mr. Hackett is a former director of Halliburton Company and Bunge Ltd. and the former Chairman of the Board of the Federal Reserve Bank of Dallas. He is the immediate past Chairman of the National Petroleum Council, a member of the Society of Petroleum Engineers and Chairman of the Baylor College of Medicine Board of Trustees. Mr. Hackett is also a former adjunct Professor of Finance at Rice University.

Charles E. McMahen. Mr. McMahen was elected a director of Enterprise GP in November 2010 and serves as Chairman of its Audit and Conflicts Committee. He served as a director of Holdings GP from August 2005 to November 2010. Mr. McMahen served as Vice Chairman of Compass Bank from March 1999 until December 2003 and served as Vice Chairman of Compass Bancshares from April 2001 until his retirement in December 2003. Mr. McMahen also served as Chairman and CEO of Compass Banks of Texas from March 1990 until March 1999. Mr. McMahen has served as a director of Compass Bancshares, and its successor, BBVA Compass Bank (a wholly owned subsidiary of BBVA), since 2001. He also serves as a director for BBVA Compass Bancshares, Inc. (a wholly owned subsidiary of BBVA and a bank holding company for BBVA's North American banking operations). Mr. McMahen serves on the Audit Committee for BBVA Compass Bancshares, Inc. and as Chairman of its Risk Committee. Mr. McMahen served as Chairman of the Board of Regents of the University of Houston from September 1998 to August 2000.

Richard S. Snell. Mr. Snell, a Certified Public Accountant, was elected a director of Enterprise GP in September 2011 and serves on its Audit and Conflicts Committee. He previously served as a director of DEP GP from January 2010 until September 2011. Mr. Snell also served as a director of the general partner of TEPPCO Partners, L.P. ("TEPPCO") from January 2006 until October 2009. From June 2000 until February 2006, he served as a director of EPGP. He is Of Counsel with the law firm of Thompson & Knight LLP, having been with the firm since 2000. Prior to his position with Thompson & Knight LLP, he worked as an attorney for the Snell & Smith, P.C. law firm from its founding in 1993 until 2000.

A. James Teague. Mr. Teague was elected COO and a director of Enterprise GP in November 2010 and served as an Executive Vice President of Enterprise GP from November 2010 until February 2013. He served as Executive Vice President of EPGP from November 1999 to November 2010 and additionally as a director from July 2008 to November 2010 and as Chief Operating Officer from September 2010 to November 2010. In addition, he served as EPGP's Chief Commercial Officer from July 2008 until September 2010. He served as Executive Vice President and Chief Commercial Officer of DEP GP from July 2008 until September 2011. He previously served as a director of DEP GP from July 2008 to May 2010 and as a director of Holdings GP from October 2009 to May 2010. Mr. Teague joined Enterprise in connection with its purchase of certain midstream energy assets from affiliates of Shell Oil Company in 1999. From 1998 to 1999, Mr. Teague served as President of Tejas Natural Gas Liquids, LLC, then an affiliate of Shell. From 1997 to 1998, he was President of Marketing and Trading for Mapco Inc.

Graham W. Bacon. Mr. Bacon was elected as Group Senior Vice President, Operations and Environmental, Health, Safety & Training of Enterprise GP in February 2014. He previously served as a Senior Vice President, Operations from January 2012 to February 2014, as a Vice President, Operations from June 2006 to January 2012, and as a Vice President, Engineering from September 2005 to May 2006. He joined Enterprise in 1991 and has held a variety of operations and engineering roles. Prior to joining Enterprise, Mr. Bacon worked for Vista Chemical Company.

G. R. Cardillo. Mr. Cardillo was elected as Group Senior Vice President, Transportation and Distribution of Enterprise GP in February 2015. He previously served as Senior Vice President (Propylene and Marine) from February 2011 to February 2015. Mr. Cardillo joined us in connection with our purchase of certain petrochemical storage and propylene fractionation assets from affiliates of Ultramar Diamond Shamrock Corp. and Koch Industries Inc. ("Diamond Koch") in 2002. From 2000 to 2002, Mr. Cardillo served as a Vice President in charge of propylene

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commercial activities for Diamond Koch. Mr. Cardillo served as a Vice President of EPGP from November 2004 to November 2010 and of Enterprise GP from November 2010 to February 2011. Mr. Cardillo has been an integral part of our Petrochemicals management team since joining us in 2002 and assumed leadership of this commercial function in June 2008. He assumed leadership of our marine services operations in July 2010.

Craig W. Murray. Mr. Murray was elected as Group Senior Vice President and General Counsel in January 2015. Prior to joining us, Mr. Murray served as a Partner at Vinson & Elkins LLP in Houston, Texas from April 1976 to December 2014, with his most recent role being that of a Senior Partner. At Vinson & Elkins, Mr. Murray focused primarily on corporate and energy-related finance matters, with a special emphasis on structured finance, asset securitization, and project finance transactions. Mr. Murray's experience in energy finance has involved oil and gas properties in Texas, Louisiana, and all major oil and gas producing states, as well as offshore properties in the Gulf of Mexico. Mr. Murray is a member of the American Bar Association, Texas Bar Association and Houston Bar Association and has been recognized in numerous publications for his professional accomplishments.

William Ordemann. Mr. Ordemann was elected a director of Oiltanking GP in October 2014. He was elected a Group Senior Vice President of Enterprise GP in April 2012 and is responsible for Enterprise's onshore and offshore natural gas and crude oil pipelines, natural gas processing and storage assets, as well as NGL fractionation and storage facilities. He previously served as Executive Vice President of Holdings GP from August 2007 to November 2010 and as Executive Vice President of Enterprise GP from November 2010 to April 2012. He also served as COO of EPGP from August 2007 until September 2010 and as its Executive Vice President from August 2007 to November 2010. He was also elected an Executive Vice President of DEP GP in August 2007 and served in such role until September 2011. He previously served as a Senior Vice President of EPGP from September 2001 to August 2007 and was a Vice President of EPGP from October 1999 to September 2001. Mr. Ordemann joined Enterprise in connection with our purchase of certain midstream energy assets from affiliates of Shell Oil Company in 1999. Prior to joining Enterprise, he was a Vice President of Shell Midstream Enterprises, LLC from January 1997 to February 1998, and Vice President of Tejas Natural Gas Liquids, LLC from February 1998 to September 1999.

Michael C. Smith. Mr. Smith was elected a director of Oiltanking GP in October 2014. He was elected a Group Senior Vice President of Enterprise GP in January 2014 and is responsible for Enterprise's regulated businesses. He previously served as Senior Vice President, Unregulated NGL Business from April 2012 to January 2014, as Vice President, Western Gas Gathering & Processing from January 2010 to April 2012, as Vice President, Rocky Mountain Gathering from January 2009 to December 2009, as Director, Rocky Mountains, January 2006 to January 2009, and as Director, Commercial Development from October 2002 to December 2005. Prior to joining Enterprise, Mr. Smith served in marketing, engineering, and project management roles with Mapco Inc. and The Williams Companies.

Bryan F. Bulawa. Mr. Bulawa was elected a director and Chairman of the Board of Oiltanking GP in October 2014. He was elected a Senior Vice President and the Treasurer of Enterprise GP in November 2010. He previously served as Senior Vice President, CFO and Treasurer of DEP GP from April 2010 until September 2011 and a director of DEP GP from February 2011 to September 2011. He also served as Senior Vice President and Treasurer of EPGP and Holdings GP from October 2009 to November 2010, as Senior Vice President and Treasurer of DEP GP from October 2009 to April 2010, and as Vice President and Treasurer of EPGP from July 2007 to October 2009. He has also served as Senior Vice President and Treasurer of EPCO since May 2010. Prior to joining Enterprise, Mr. Bulawa spent 13 years at Scotia Capital, where he last served as director of the firm's U.S. Energy Corporate Finance and Distribution group.

Michael J. Knesek. Mr. Knesek, a Certified Public Accountant, was elected the Senior Vice President, Controller and Principal Accounting Officer of Enterprise GP in November 2010. From February 2005 to November 2010, Mr. Knesek served as Senior Vice President of EPGP, having previously served as a Vice President of EPGP since August 2000. Mr. Knesek served as the Principal Accounting Officer and Controller of DEP GP from September 2006 to September 2011. He served as the Principal Accounting Officer and Controller of Holdings GP from August 2005 to November 2010 and served in the same capacity for EPGP from August 2000 to November 2010. He also served as Senior Vice President of DEP GP from September 2006 to September 2011. Mr. Knesek has been the Controller of EPCO since 1990 and currently serves as one of its Senior Vice Presidents.

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Director Experience, Qualifications, Attributes and Skills

The following is a brief discussion of the experience, qualifications, attributes or skills that led to the conclusion that each of the following persons should serve as a director of our general partner.

Four of our directors are current employees of EPCO and officers of our general partner or its affiliates. Each of these directors has significant experience in our industry as executive officers as well as other qualifications, attributes and skills. These include: for Ms. Williams, legal and community involvement with numerous charitable organizations, and active involvement in EPCO's businesses, including ownership and management of Enterprise's businesses; for Mr. Creel, over 30 years of management experience with midstream assets, for both third parties and Enterprise, including finance and accounting (Certified Public Accountant) and more than eight years of management experience in the financial industry; for Mr. Fowler, over 11 years of experience with our midstream assets, including finance, accounting (inactive Certified Public Accountant) and investor relations and, for over the last eight years, as a member of our executive management team; and for Mr. Teague, over 40 years of commercial management of midstream assets and marketing and trading activities, both for third parties and for Enterprise's businesses.

Our six outside voting directors also have significant experience in the energy industry in a variety of capacities, as well as other qualifications, attributes and skills. These include: for Mr. Andress, oil and gas exploration and production; for Mr. Barnett, legal, regulatory and management skills as a former managing partner of an international law firm; for Dr. Flach, executive management of an international energy supply, trading and logistics company; for Mr. Hackett, executive management of a major oil and gas exploration and production company; for Mr. McMahen, banking and finance; and for Mr. Snell, legal and accounting matters and previous board service for other publicly traded midstream partnerships.

As advisory directors, Mr. Casey has executive management experience in NGL and petrochemicals trading and related storage businesses and Mr. Smith has experience in banking and investment matters. As an honorary director, Mr. Andras has a long history with Enterprise and its operations, including being a former CEO.

Section 16(a) Beneficial Ownership Reporting Compliance

Under federal securities laws, directors and executive officers of Enterprise GP and any persons holding more than 10% of our common units are required to report their beneficial ownership of common units and any changes in their beneficial ownership levels to us and the SEC. Specific due dates for these reports have been established by regulation, and we are required to disclose in this annual report any failure to file this information within the specified timeframes. All such reporting was done in a timely manner in 2014.

Item 11. Executive Compensation.

Executive Officer Compensation

We do not directly employ any of the persons responsible for managing our business. Instead, we are managed by our general partner, the executive officers of which are employees of EPCO. Our management, administrative and operating functions are primarily performed by employees of EPCO in accordance with the ASA. Pursuant to the ASA, we reimburse EPCO for 100% of its compensation costs related to the employment of personnel working on our behalf. For information regarding the ASA, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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Summary Compensation Table

The following table presents total compensation amounts paid, accrued or otherwise expensed by us with respect to the years ended December 31, 2014, 2013 and 2012 for the CEO, the CFO, and the three other most highly compensated executive officers of our general partner. Collectively, these individuals were our "named executive officers" for 2014.

		Cash		Cash		Unit		Option		All Other
Name and		Salary		Bonus		Awards		Awards		Compensation		Total
Principal Position	Year	($)		($) (1)		($) (2)		($)		($) (3)		($)
Michael A. Creel	2014	$	775,000	$	1,750,000	$	4,691,680		--	$	10,389,474	$	17,606,154
(CEO)	2013		775,000		1,750,000		4,123,342		--		575,115		7,223,457
	2012		769,000		1,550,000		3,738,240		--		597,606		6,654,846

W. Randall Fowler	2014		427,973		562,500		2,230,200		--		4,011,435		7,232,108
(Executive Vice President and CFO)	2013		418,144		562,500		2,141,625		--		302,824		3,425,093
	2012		415,097		562,500		1,947,000		--		312,216		3,236,813

A. James Teague	2014		753,788		1,750,000		4,691,680		--		10,515,870		17,711,338
(COO)	2013		690,150		1,750,000		4,123,342		--		489,233		7,052,725
	2012		685,150		1,550,000		3,364,416		--		459,763		6,059,329

William Ordemann	2014		433,400		327,000		1,321,600		--		2,694,010		4,776,010
(Group Senior Vice President)	2013		425,150		400,000		1,142,200		--		234,962		2,202,312
	2012		422,900		300,000		1,038,400		--		294,486		2,055,786

Stephanie C. Hildebrandt (4)	2014		382,875		--		1,189,440		--		4,183,885		5,756,200
(Former Senior Vice President,	2013		375,000		250,000		1,142,200		--		181,598		1,948,798
General Counsel and Secretary)	2012		368,750		250,000		1,038,400		--		169,183		1,826,333

(1) Amounts represent discretionary annual cash awards accrued with respect to the years presented. Cash awards are paid in February of the following year (e.g., the 2014 cash bonuses were paid in February 2015). (2) Amounts represent our estimated share of the aggregate grant date fair value of equity-based awards granted during each year presented. For information about assumptions made in the valuation of these awards, see Note 5 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report, the applicable disclosures of which are incorporated by reference into this Item 11. (3) Amounts include (i) contributions in connection with funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid on incentive plan awards, (iii) the imputed value of life insurance premiums paid on behalf of the officer, (iv) employee retention payments and (v) other amounts. See the following table for additional information. (4) Ms. Hildebrandt resigned effective December 31, 2014.

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The following table presents the components of "All Other Compensation" for each named executive officer for the year ended December 31, 2014:

	Contributions Under Funded, Qualified, Defined Contribution Retirement Plans		Quarterly Distributions Paid On Incentive Plan Awards		Life Insurance Premiums		Employee Retention Payments (1)		Other		Total All Other Compensation
Michael A. Creel	$	28,600	$	507,203	$	4,356	$	9,841,667	$	7,648	$	10,389,474
W. Randall Fowler		21,450		256,151		2,129		3,727,083		4,622		4,011,435
A. James Teague		28,600		473,303		8,382		10,000,000		5,585		10,515,870
William Ordemann		31,200		154,315		2,838		2,500,000		5,657		2,694,010
Stephanie C. Hildebrandt (2)		28,600		147,933		1,518		--		4,005,834		4,183,885

(1) Amounts presented relate to retention payments made pursuant to retention agreements entered into with such officers during 2010. For further information, please see the description of these agreements and payments under "Compensation Discussion and Analysis" below. The amounts charged to us for each officer reflect the percentage of time each officer spent on our business and affairs since the retention agreements were originally executed. (2) Amounts presented under "Other" for Ms. Hildebrandt include a $4.0 million payment made to her in connection with her resignation effective as of December 31, 2014.

Compensation Discussion and Analysis

With respect to our named executive officers, compensation paid or awarded by us for the last three fiscal years reflects only that portion of compensation paid by EPCO and allocated to us pursuant to the ASA, including an allocation of a portion of the cost of equity-based long-term incentive plans of EPCO. The EPCO Trustees control EPCO and provide recommendations with respect to the compensation of our CEO and COO. As described further below, the Audit and Conflicts Committee of our general partner has ultimate decision-making authority with respect to compensation for each of our CEO and COO, and our CEO and COO have ultimate decision-making authority with respect to compensation for our other named executive officers. The following elements of compensation, and EPCO's decisions with respect to determination of payments, are not subject to approvals by the Board or the Audit and Conflicts Committee of our general partner, except in the case of compensation paid to each of our CEO and COO (as described below). Neither EPCO nor our general partner has a separate compensation committee; however, equity-based awards granted under EPCO's long-term incentive plans to officers of our general partner (including our named executive officers) are approved by the Audit and Conflicts Committee.

As discussed below, the elements of EPCO's compensation program, along with EPCO's other incentives (e.g., benefits, work environment and career development), are intended to provide a total rewards package to employees. The objectives of EPCO's compensation program are to provide competitive compensation opportunities that will align and drive employee performance toward the creation of sustained long-term unitholder value. Our compensation program allows us to attract, motivate and retain high quality talent with the skills and competencies we require. The compensation package is designed to reward contributions by employees in support of the business strategies of EPCO and its affiliates at both our partnership and individual levels. With respect to the three years ended December 31, 2014, EPCO's compensation package for named executive officers did not include any elements based on targeted performance-related criteria.

The primary elements of EPCO's compensation program for named executive officers (those currently serving our partnership) are a combination of annual cash and long-term equity-based incentive compensation. For the three years ended December 31, 2014, the primary elements of compensation for Messrs. Creel, Fowler, Teague and Ordemann consisted of annual cash base salary, discretionary annual cash bonus awards, equity-based awards under long-term incentive arrangements and other compensation, including very limited perquisites. For the year ended December 31, 2014, other compensation for each of these four individuals also included a cash retention bonus (as described below). Ms. Hildebrandt resigned effective December 31, 2014. The primary elements of her compensation for the two years ended December 31, 2013 were annual cash base salary, discretionary annual cash bonus awards, equity-based awards under long-term incentive arrangements and other compensation, including very

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limited perquisites. For the year ended December 31, 2014, the primary elements of her compensation were an annual cash base salary, equity-based awards under long-term incentive arrangements and other compensation, including a $4.0 million payment made to her in connection with her resignation effective as of December 31, 2014 and very limited perquisites.

In order to assist our CEO, COO, EPCO and the Audit and Conflicts Committee with compensation decisions, EPCO's senior vice president of Human Resources formulates preliminary compensation recommendations for each of the named executive officers, including our CEO and COO. With respect to compensation to be paid to each of our CEO and COO, the EPCO Trustees consider such preliminary recommendation and make revisions, if appropriate. Afterwards, EPCO's senior vice president of Human Resources presents the revised compensation recommendations for each of our CEO and COO to the members of the Audit and Conflicts Committee, which consider the recommendations and then make a final determination regarding compensation of each of our CEO and COO. In making their final determination, the Audit and Conflicts Committee may discuss the recommendations with EPCO's senior vice president of Human Resources, request to discuss the recommendations with EPCO's compensation consultant, and/or retain its own compensation consultant.

With respect to compensation to be paid to the remaining named executive officers other than our CEO and COO, the CEO and COO consider the preliminary recommendations of EPCO's senior vice president of Human Resources and make revisions, if appropriate. The CEO and COO make a final determination regarding compensation of these named executive officers.

In making these compensation decisions, EPCO considers market data for determining relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, relevant compensation surveys and reports. These surveys and reports are conducted and prepared by a third party compensation consultant. In 2013, EPCO engaged Meridian Compensation Partners, LLC (the "Consultant") to complete a detailed review of executive compensation relative to our industry. In connection with this review, the Consultant provided comparative market data on compensation practices and programs for executive level positions based on an analysis of industry competitors and other large companies. The market data for industry competitors included information from Anadarko Petroleum Corporation; CenterPoint Energy, Inc.; CMS Energy Corporation; Dominion Resources, Inc.; Enbridge Energy Partners, L.P.; Energy Transfer Partners, L.P.; Kinder Morgan Inc.; NiSource Inc.; ONEOK, Inc.; Plains All American Pipeline, L.P.; Spectra Energy Corp.; Sunoco Logistics Partners; The Williams Companies, Inc.; and TransCanada Corporation. The market data for other large companies included 75 entities across multiple industries, including well-known companies such as Merck & Co., Inc.; The Home Depot, Inc.; Caterpillar Inc.; Target Corporation; and Honeywell International Inc., among others.

Neither we, nor EPCO, which engages the Consultant, are aware of the specific data of the companies included in the Consultant's proprietary database for specific positions. EPCO uses the information provided in the Consultant's analysis to gauge whether compensation levels reported by the Consultant and the general ranges of compensation for EPCO employees in similar positions are comparable, but that comparison is only a factor taken into consideration and may or may not impact compensation of our named executive officers, for which our Audit and Conflicts Committee (in the case of our CEO's and COO's compensation) or our CEO and COO (in the case of compensation to be paid to our other named executive officers) have the ultimate decision-making authority. EPCO does not otherwise engage in benchmarking for the named executive officers' positions.

The Audit and Conflicts Committee, our CEO, our COO and EPCO do not use any formula or specific performance-based criteria in determining the compensation of our named executive officers for services they perform for us; rather, the Audit and Conflicts Committee or our CEO and COO (as applicable) and EPCO determine an appropriate level and mix of compensation on a case-by-case basis. Further, there is no established policy or target for the allocation between either cash and non-cash or short-term and long-term incentive compensation. However, some considerations that the Audit and Conflicts Committee or our CEO and COO (as applicable) may take into account in making the case-by-case compensation determinations include total value of all elements of compensation and the appropriate balance of internal pay equity among executive officers. The Audit and Conflicts Committee, our CEO, our COO and EPCO also consider individual performance, levels of responsibility and value to the organization. All compensation determinations are subjective and discretionary and, as noted above, subject to the ultimate decision-making authority of the Audit and Conflicts Committee or our CEO and COO (as applicable), except for equity-based awards under EPCO's long-term incentive plans, as discussed

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below.

We believe that the absence of specific performance-based criteria associated with our cash compensation and equity-based awards, and the long-term nature of our equity-based awards, has the effect of discouraging excessive risk taking by our executive officers in order to reach certain targets. Further, the practice of making compensation decisions on a case-by-case basis permits consideration of flexible criteria, including current overall market conditions.

Changes in the base salaries of our named executive officers during the three years ending December 31, 2014 were largely budget-driven and made consistent relative to increases in the base salaries of our other executive officers.

The discretionary cash bonus awards paid to each of our named executive officers were determined by consultation, as appropriate, among the EPCO Trustees, our CEO, our COO and EPCO's senior vice president of Human Resources, subject to final determination by the Audit and Conflicts Committee (in the case of our CEO's and COO's cash bonus awards) and our CEO and COO (in the case of cash bonus awards to be paid to our other named executive officers). These cash bonus awards, in combination with annual base salaries, are intended to yield competitive total cash compensation levels for the named executive officers and drive performance in support of our business strategies, as well as the performance of other EPCO affiliates for which the named executive officers may perform services. It is EPCO's general policy to pay these awards in February of the following year. The discretionary cash bonuses reflect the Audit and Conflicts Committee's (with respect to our CEO and COO) and our CEO's and COO's (with respect to the other named executive officers) general consideration of our financial performance for those periods, without any weight or formula given to any specific financial performance measures, as well as their subjective judgment of each named executive officer's general contributions in connection with our performance, again without any weight or formula given to any specific individual contribution or accomplishments. The levels of cash bonuses were also based on the level and position of such named executive officers and the relative compensation paid to our other executive officers.

Equity-based awards granted to our named executive officers under EPCO's long-term incentive plans were determined by consultation among the EPCO Trustees, our CEO, our COO and EPCO's senior vice president of Human Resources, and were approved by the Audit and Conflicts Committee. Each of our named executive officers were granted restricted common unit awards in the two years ended December 31, 2013 and phantom unit awards in the year ended December 31, 2014. The levels of EPCO's equity-based awards to our named executive officers during the last three years also reflected the Audit and Conflicts Committee's (with respect to our CEO and COO) and our CEO's and COO's (with respect to the other named executive officers) general consideration of our financial performance for those periods, without any weight or formula given to any specific financial performance measures, as well as their subjective judgment of each named executive officer's general contributions in connection with our performance, again without any weight or formula given to any specific individual contribution or accomplishments. The levels of equity-based awards were also based on the level and position of such named executive officers and the relative compensation paid to our other executive officers.

EPCO expects to continue its policy of paying for limited perquisites attributable to our named executive officers. EPCO also makes matching contributions under its defined contribution plans for the benefit of our named executive officers in the same manner as it does for other EPCO employees.

EPCO does not offer our named executive officers a defined benefit pension plan. Also, none of our named executive officers had nonqualified deferred compensation during the three years ended December 31, 2014.

In the fourth quarter of 2014, Messrs. Creel, Fowler, Teague and Ordemann received cash employee retention payments of $10 million, $5 million, $10 million and $2.5 million, respectively, less applicable tax withholdings. These payments were made in connection with retention agreements that EPCO entered into with each named executive officer in the fourth quarter of 2010. The effective date of the retention agreement for Mr. Ordemann was October 1, 2010. The effective date of the retention agreements for Messrs. Creel, Fowler and Teague was December 1, 2010. We were allocated all or a portion of these payments based on the amount of time each officer spent on our affairs since entering into these agreements. The purpose of the retention agreements was to reinforce and encourage the continued dedication of such officers to EPCO and us as a member of our executive

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management team. In order to qualify for the retention payments, each executive officer was required to complete 48 months of continuous employment with EPCO from the effective date of each officer's retention agreement.

Ms. Hildebrandt resigned her position as Senior Vice President, General Counsel and Secretary of our general partner effective December 31, 2014. In connection with her departure, Ms. Hildebrandt and EPCO entered into an Agreement and Release, in which EPCO agreed to pay Ms. Hildebrandt a lump sum amount of $4.0 million in cash and twelve months medical benefits in satisfaction of any obligations owed to Ms. Hildebrandt by EPCO or any of its affiliates. As consideration for these payments, Ms. Hildebrandt agreed, among other things, not to disclose confidential information or trade secrets of EPCO or its affiliates, not to solicit employees of EPCO for employment for a period of one year following December 31, 2014, and to waive her right to bring certain claims against EPCO or its affiliates. As a result of her resignation, Ms. Hildebrandt forfeited any discretionary cash bonus that she might have received for the year ended December 31, 2014 and all of her unvested equity-based incentive awards as of December 31, 2014.

Under the ASA, the compensation costs of our named executive officers, including those costs related to equity-based awards, are allocated between us and other affiliates of EPCO based on the estimated amount of time that each officer spends on our consolidated businesses in any fiscal year. These percentages are reassessed at least quarterly. The following table presents the average approximate amount of time devoted by each of our named executive officers to our consolidated businesses and to EPCO and its other privately held affiliates during each of the years indicated.

		Enterprise	EPCO and	Total
		Products	its other	Time
Named Executive Officer	Year	Partners	affiliates	Allocated
Michael A. Creel (CEO)	2014	100%	--	100%
	2013	100%	--	100%
	2012	100%	--	100%

W. Randall Fowler (CFO)	2014	75%	25%	100%
	2013	75%	25%	100%
	2012	75%	25%	100%

A. James Teague	2014	100%	--	100%
	2013	100%	--	100%
	2012	100%	--	100%

William Ordemann	2014	100%	--	100%
	2013	100%	--	100%
	2012	100%	--	100%

Stephanie C. Hildebrandt	2014	100%	--	100%
	2013	100%	--	100%
	2012	100%	--	100%

In conclusion, we believe that each of the base salary, discretionary cash bonus awards, long-term incentive awards and retention agreements, as applicable, fit the overall compensation objectives of us and of EPCO and are designed to avoid risks that are likely to conflict with our risk management policies.

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Grants of Plan-Based Awards in Fiscal Year 2014

The following table presents information concerning each 2014 grant of a plan-based award to a named executive officer for which we will be allocated our pro rata share of the related cost under the ASA.

										Grant
								Exercise		Date Fair
								or Base		Value of
		Estimated Future Payouts Under						Price of		Unit and
		Equity Incentive Plan Awards						Option		Option
	Grant	Threshold		Target		Maximum		Awards		Awards
Name	Date	(#)		(#)		(#)		($/Unit)		($) (1,2)
Phantom unit awards:
Michael A. Creel (CEO)	2/19/14		--		142,000		--		--	$	4,691,680
W. Randall Fowler (CFO)	2/19/14		--		90,000		--		--		2,230,200
A. James Teague	2/19/14		--		142,000		--		--		4,691,680
William Ordemann	2/19/14		--		40,000		--		--		1,321,600
Stephanie C. Hildebrandt	2/19/14		--		36,000		--		--		1,189,440

(1) Amounts presented reflect that portion of grant date fair value allocable to us based on the average percentage of time each named executive officer spent on our consolidated businesses during 2014. Based on current allocations, we estimate that the consolidated compensation expense we record for Messrs. Creel, Fowler, Teague and Ordemann with respect to the phantom unit awards will approximate these grant date fair value amounts over the vesting period. Since Ms. Hildebrandt resigned effective December 31, 2014, her phantom unit award was forfeited; therefore, we will not recognize any expense in connection with such award. (2) The closing price of our common units on February 19, 2014 was $33.04 per unit.

In connection with the phantom unit awards noted above, each named executive officer was granted distribution equivalent rights ("DERs," see description below). The phantom unit awards and the associated DERs granted to the named executive officers in 2014 were made under the 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (the "2008 Plan").

Grant date fair value amounts presented in the preceding table are based on certain assumptions and considerations made by management. See Note 5 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding our fair value assumptions made in connection with equity-based compensation.

Summary of Long-Term Incentive Arrangements Underlying 2014 Award Grants

The 2008 Plan provides for incentive awards to EPCO's key employees and non-employee directors and consultants who perform management, administrative or operational functions for us or our affiliates. Awards granted under the 2008 Plan may be in the form of unit options, restricted common units, phantom units, DERs, unit appreciation rights ("UARs") and other unit-based awards or substitute awards. As of December 31, 2014, no UARs have been granted to employees under the 2008 Plan.

Phantom unit awards allow recipients to acquire our common units (at no cost to the recipient apart from fulfilling service and other conditions) once a defined vesting period expires, subject to customary forfeiture provisions. Phantom unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire. The fair value of a phantom unit award is based on the market price per unit of our common units on the date of grant. For financial statement purposes, compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures.

A DER entitles the recipient to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the recipient (on the date of record for each quarterly cash distribution to common unitholders) and the cash distribution per common unit paid by us to our common unitholders. The following cash payments were made to the named executive officers in connection with their outstanding phantom unit awards and tandem DERs during the year ended December 31, 2014: Mr. Creel – $153,360; Mr. Fowler – $97,200; Mr. Teague – $153,360; Mr. Ordemann – $43,200; and Ms. Hildebrandt – $38,880. Since our phantom

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unit awards are expected to result in the issuance of common units at vesting, cash payments made in connection with the DERs are charged to partners' equity.

Equity-Based Awards Outstanding at December 31, 2014

The following information summarizes each named executive officer's long-term incentive awards outstanding at the close of business on December 31, 2014.

		Option Awards								Unit Awards
		Number of		Number of								Market
		Units		Units						Number		Value
		Underlying		Underlying		Option				of Units		of Units
		Options		Options		Exercise		Option		That Have		That Have
	Vesting	Exercisable		Unexercisable		Price		Expiration		Not Vested		Not Vested
Name	Date	(#)		(#)		($/Unit)		Date		(#) (1)		($) (2)
Restricted common unit awards: (3)
Michael A. Creel (CEO)	Various (1)		--		--		--		--		212,100	$	7,661,052
W. Randall Fowler (CFO)	Various (1)		--		--		--		--		147,000		5,309,640
A. James Teague	Various (1)		--		--		--		--		195,100		7,047,012
William Ordemann	Various (1)		--		--		--		--		65,000		2,347,800

Phantom unit awards: (4)
Michael A. Creel (CEO)	Various (1)		--		--		--		--		142,000	$	5,129,040
W. Randall Fowler (CFO)	Various (1)		--		--		--		--		90,000		3,250,800
A. James Teague	Various (1)		--		--		--		--		142,000		5,129,040
William Ordemann	Various (1)		--		--		--		--		40,000		1,444,800

Unit option awards:
Michael A. Creel (CEO):
February 23, 2010 option grant (5)	2/23/14		--		180,000	$	16.14	12/31/15			--		--
W. Randall Fowler (CFO):
February 23, 2010 option grant (5)	2/23/14		--		120,000		16.14	12/31/15			--		--
A. James Teague:
February 23, 2010 option grant (5)	2/23/14		--		120,000		16.14	12/31/15			--		--
William Ordemann:
February 23, 2010 option grant (5)	2/23/14		--		120,000		16.14	12/31/15			--		--
Stephanie C. Hildebrandt
February 23, 2010 option grant (5)	2/23/14		--		30,000		16.14	02/28/15			--		--

(1) Amounts represent the total number of awards outstanding for each named executive officer. (2) Amounts derived by multiplying the total number of restricted common unit or phantom unit awards outstanding for each named executive officer by the closing price of our common units at December 31, 2014 (the last trading day of 2014) of $36.12 per unit. (3) Of the 619,200 non-vested restricted common unit awards presented in the table, 301,400 vest in 2015, 210,600 vest in 2016, and 107,200 vest in 2017. (4) Of the 414,000 non-vested phantom unit awards presented in the table, 103,500 vest in each of the years 2015, 2016, 2017 and 2018. (5) These option grants are exercisable beginning in February 2015.

EPCO's long-term incentive plans provide for the issuance of non-qualified incentive options. These unit option awards are denominated in our common units. When issued, the exercise price of each unit option award may be no less than the market price of our common units on the date of grant. In general, unit option awards have a vesting period of four years from the date of grant and expire at the end of the calendar year following the year of vesting (e.g., an option vesting on February 23, 2014 will expire on December 31, 2015). However, unit option awards only become exercisable at certain times during the calendar year (typically the months of February, May, August and November) following the year in which they vest.

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Option Exercises and Units Vested

The following table presents the exercise of unit options by and vesting of restricted common units to our named executive officers during the year ended December 31, 2014. These amounts are presented on a gross basis and do not reflect any allocation of compensation to other entities under the ASA.

	Option Awards				Restricted Common Unit Awards
	Number of				Number of
	Units		Value		Units		Value
	Acquired on		Realized on		Acquired on		Realized on
	Exercise		Exercise		Vesting		Vesting
Name	(#) (1)		($) (2)		(#) (1)		($) (3)
Michael A. Creel (CEO):
Option awards		330,000	$	6,892,050
Restricted common unit awards						144,400	$	4,741,206
W. Randall Fowler (CFO):
Option awards		225,000		4,703,025
Restricted common unit awards						97,500		3,201,363
A. James Teague:
Option awards		240,000		5,028,000
Restricted common unit awards						117,000		3,842,781
William Ordemann:
Option awards		210,000		4,378,050
Restricted common unit awards						51,900		1,703,730
Stephanie C. Hildebrandt:
Option awards		45,000		947,550
Restricted common unit awards						38,750		1,293,769

(1) Represents the gross number of common units acquired upon exercise of unit options and vesting of restricted common unit awards before adjustments for applicable tax withholdings. (2) Amount determined by multiplying the number of gross common units acquired upon exercise of unit options by the difference between the closing price of our common units on the date of exercise and the exercise price. (3) Amount determined by multiplying the gross number of restricted common unit awards that vested during 2014 by the closing price of our common units on the date of vesting.

Potential Payments Upon Termination or Change-in-Control

Messrs. Creel, Fowler, Teague and Ordemann do not have any employment agreements that call for payment of termination or severance benefits or provide for any payments in the event of a change in control of our general partner. As described in Compensation Discussion and Analysis, Ms. Hildebrandt and EPCO entered into an Agreement and Release in December 2014, which provided for a $4.0 million payment to her in connection with her resignation effective as of December 31, 2014.

Vesting of equity-based awards under EPCO's long-term incentive plans are subject to acceleration upon a qualifying termination, including termination after a change of control of our general partner. Qualifying termination under such awards generally means a termination as an employee of EPCO or an affiliated group member (i) upon death, (ii) a qualifying long-term disability, (iii) a qualifying retirement, or (iv) within one year after a change of control (as defined), other than a termination for cause (as defined) or termination by such person that is not a qualifying termination for good reason (as defined). A change of control under these award agreements is generally defined to mean that Dan L. Duncan, his descendants, heirs and/or legatees and/or distributees of Dan L. Duncan's estate, and/or trusts (including, without limitation, one or more voting trusts) established for the benefit of his descendants, heirs and/or legatees and/or distributees, collectively, cease, directly or indirectly, to control our general partner. Mr. Duncan passed away in March 2010.

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As of December 31, 2014, the estimated market value of unvested unit option awards that could be realized in connection with an accelerated vesting for a qualifying termination (calculated as the difference between the exercise prices of the underlying options and the closing price of our common units on December 31, 2014 of $36.12 per unit, but without reflecting any allocation of compensation to other entities under the ASA), would have been the following for each of the named executive officers except for Ms. Hildebrandt:

	Accelerated Option Value
Michael A. Creel (CEO)	$	3,597,300
W. Randall Fowler (CFO)		2,398,200
A. James Teague		2,398,200
William Ordemann		2,398,200

Although the long-term incentive plan awards are entered into between EPCO and the named executive officer, all or an allocated portion of the compensation related to these agreements may be charged to us in accordance with the ASA.

Compensation Committee Report

We do not have a separate compensation committee. In addition, we do not directly employ or compensate our named executive officers. Rather, under the ASA, we reimburse EPCO for the compensation of our executive officers. As described in Compensation Discussion and Analysis, decisions regarding the compensation of our named executive officers are made, as applicable, by EPCO, our CEO and COO, and the Audit and Conflicts Committee of our general partner.

In light of the foregoing, the Board has reviewed and discussed with management the Compensation Discussion and Analysis set forth above and determined that it be included in this annual report for the year ended December 31, 2014.

Submitted by: Randa Duncan Williams

Thurmon M. Andress

E. William Barnett

Michael A. Creel

Dr. F. Christian Flach

W. Randall Fowler

James T. Hackett

Charles E. McMahen

Richard S. Snell

A. James Teague

Notwithstanding anything to the contrary set forth in any previous filings under the Securities Act, as amended, or the Securities Exchange Act, as amended, that incorporate future filings, including this annual report, in whole or in part, the foregoing Compensation Committee Report shall not be incorporated by reference into any such filings.

Compensation Committee Interlocks and Insider Participation

None of the directors or executive officers of our general partner served as members of the compensation committee of another entity that has or had an executive officer who served as a member of our Board during the year ended December 31, 2014. As previously noted, we do not have a separate compensation committee. As described in Compensation Discussion and Analysis, decisions regarding the compensation of our named executive officers are made, as applicable, by EPCO, our CEO and COO, and the Audit and Conflicts Committee of our general partner.

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Director Compensation

Neither we nor our general partner provide any additional compensation to employees of EPCO who serve as directors of our general partner. Likewise, Dr. Flach does not receive any compensation for his services.

During 2014, the independent voting directors of our general partner were compensated as follows: (i) each received a $75,000 annual cash retainer; (ii) if the individual served as chairman of a committee of the Board, then he received an additional $15,000 annual cash retainer; (iii) each received a meeting fee of $1,500 in cash for each meeting of the Board attended; (iv) each received a meeting fee of $1,500 in cash for each meeting of a duly appointed committee of the Board attended, provided that he was duly elected or appointed to the committee at the time of such meeting; and (v) each received an annual grant of our common units having a fair market value, based on the closing price of such security on the trading day immediately preceding the date of grant, of approximately $75,000.

Our advisory directors, Messrs. Casey and Smith, each receive a $150,000 annual cash retainer, but no per meeting fees or equity-based awards during their service as advisory directors.

The following table summarizes compensation paid to the independent directors of our general partner during the year ended December 31, 2014:

	Fees Earned		Value of
	or Paid		Equity-Based		All Other
	in Cash		Awards		Compensation		Total
Name	($)		($)		($)		($)
Thurmon M. Andress	$	96,000	$	75,012	$	--	$	171,012

E. William Barnett (1)		108,000		75,012		--		183,012

Larry J. Casey: (2)
Voting director		27,989		75,012		--		103,001
Advisory director		102,945		--		--		102,945

James T. Hackett (3)		64,973		51,781		--		116,754

Charles E. McMahen (4)		115,500		75,012		--		190,512

Rex C. Ross (5)		31,195		75,012		--		106,207

Edwin E. Smith (2)
Voting director		27,989		75,012		--		103,001
Advisory director		102,945		--		--		102,945

Richard S. Snell		100,500		75,012		--		175,512

(1) Mr. Barnett serves as chairman of the Governance Committee. (2) Messrs. Casey and Smith served as voting directors from January 1, 2014 to April 24, 2014. Afterwards, both men served as advisory directors. (3) Mr. Hackett was elected a director on April 24, 2014. The value of his annual equity-based award was prorated based on this date. (4) Mr. McMahen serves as chairman of the Audit and Conflicts Committee. (5) Mr. Ross ceased to serve as a director effective as of April 24, 2014.

As an honorary director, O.S. Andras receives $20,000 in cash annually for his services.

On August 25, 2014, the Board adopted and approved a new compensation package for independent voting members of the Board for the period beginning on January 1, 2015 and until revised by similar Board action. Effective as of January 1, 2015, the independent voting directors of our general partner will be compensated as follows: (i) each will receive a $85,000 annual cash retainer and an annual grant of our common units having a fair market value, based on the closing price of such security on the trading day immediately preceding the date of grant,

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of approximately $85,000, (ii) if the individual serves as a chairman of the Audit and Conflicts Committee, then he will receive an additional $20,000 in cash annually; and (iii) if the individual serves as a chairman of the Governance Committee, then he will receive an additional $15,000 in cash annually. The cash portion of the compensation described above (i) will be payable quarterly and (ii) will be prorated for the number of days in a calendar quarter that an individual serves as an independent voting director and/or as a chairman of the Audit and Conflicts Committee and/or the Governance Committee.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related

Unitholder Matters.

Security Ownership of Certain Beneficial Owners

The following table sets forth certain information as of February 1, 2015, regarding each person known by Enterprise GP to beneficially own more than 5% of our limited partner units:

		Amount and
		Nature of
Title of	Name and Address	Beneficial	Percent
Class	of Beneficial Owner	Ownership	of Class
Common units	Randa Duncan Williams	684,721,631 (1)	35.3%
	1100 Louisiana Street, 10^th Floor
	Houston, Texas 77002

(1) For a detailed listing of the ownership amounts that comprise Ms. Williams' total beneficial ownership of our common units, see the table presented in the following section, "Security Ownership of Management," within this Item 12.

Security Ownership of Management

The following table sets forth certain information regarding the beneficial ownership of our common units as of February 1, 2015 by (i) our named executive officers for 2014; (ii) the current directors of Enterprise GP; and (iii) the current directors and executive officers (including named executive officers) of Enterprise GP as a group. All beneficial ownership information has been furnished by the respective directors and executive officers. Each person has sole voting and dispositive power over the securities shown unless indicated otherwise. The beneficial ownership amounts of certain individuals include options to acquire our common units that became exercisable in February 2015.

Ms. Williams is a DD LLC Trustee, an EPCO Trustee, an independent co-executor of the estate of Dan L. Duncan and a beneficiary of the estate. Ms. Williams is also currently Chairman and a Director of EPCO and Chairman of the Board and a Director of our general partner. Ms. Williams disclaims beneficial ownership of the limited partner units beneficially owned by the EPCO Trustees, the DD LLC Trustees and Mr. Duncan's estate, except to the extent of her voting and dispositive interests in such units.

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		Amount and
	Positions with	Nature Of
	Enterprise GP	Beneficial	Percent of
	at February 1, 2015	Ownership	Class
Randa Duncan Williams:	Director and Chairman of the Board
Units controlled by DD LLC Voting Trust:
Through DFI GP Holdings L.P.		81,688,412	4.2%
Through Dan Duncan LLC		41,762	*
Units controlled by EPCO Voting Trust:
Through EPCO		1,046,612	*
Through EPCO Investments, LLC		30,483,034	1.6%
Through Duncan Family Interests, Inc.		531,305,919	27.4%
Through EPCO Holdings, Inc.		15,679,258	*
Units controlled by estate of Dan L. Duncan (1)		20,222,872	1.0%
Units controlled by Alkek and Williams, Ltd.		326,000	*
Units controlled by family trusts (2)		3,914,632	*
Units owned personally (3)		13,130	*
Total for Randa Duncan Williams		684,721,631	35.3%

Thurmon M. Andress (4)	Director	77,468	*
E. William Barnett	Director	44,138	*
Michael A. Creel (5,6)	Director and CEO	1,757,764	*
Dr. F. Christian Flach	Director	--	*
W. Randall Fowler (5,7)	Director, Executive Vice President and CFO	1,355,420	*
James T. Hackett (8)	Director	18,489	*
Charles E. McMahen	Director	85,082	*
Richard S. Snell	Director	32,054	*
A. James Teague (5,9)	Director and COO	1,962,246	*
William Ordemann (5,10)	Group Senior Vice President	999,460	*
Stephanie Hildebrandt (5,11)	Former Senior Vice President and General Counsel	215,362	*
All directors and executive officers (including all named executive officers) of Enterprise GP, as a group (18 individuals in total) (12)		692,624,564	35.7%

* Represents a beneficial ownership of less than 1% of class
(1) The number of common units presented for the estate of Dan L. Duncan includes 14,230,652 common units held by DD Securities LLC. (2) The number of common units presented for Ms. Williams includes 3,039,632 common units held by family trusts for which she is the trustee but has disclaimed beneficial ownership. (3) The number of common units presented for Ms. Williams includes 9,090 common units held by her spouse and 4,040 common units held jointly with her spouse. (4) The number of common units presented for Mr. Andress includes (i) 31,064 common units held by a family partnership, (ii) 2,400 common units held by Mr. Andress' spouse and (iii) 1,424 common units held by family trusts. (5) These individuals are named executive officers for the year ended December 31, 2014. (6) The number of common units presented for Mr. Creel includes (i) 35,500 phantom units that vested in February 2015, which resulted in the issuance of an equal number of common units, and (ii) 180,000 common unit options that became exercisable in February 2015. (7) The number of common units presented for Mr. Fowler includes 500,000 common units held by a family limited partnership (for which he has disclaimed beneficial ownership except to the extent of his pecuniary interest). In addition, the number of common units presented for Mr. Fowler includes (i) 22,500 phantom units that vested in February 2015, which resulted in the issuance of an equal number of common units, and (ii) 120,000 common unit options that became exercisable in February 2015. (8) The number of common units presented for Mr. Hackett includes 7,496 common units held by family trusts. (9) The number of common units presented for Mr. Teague includes (i) 53,000 common units held by a trust and (ii) 425,473 common units held by Mr. Teague's spouse. In addition, the number of common units presented for Mr. Teague includes (i) 35,500 phantom units that vested in February 2015, which resulted in the issuance of an equal number of common units, and (ii) 120,000 common unit options that became exercisable in February 2015. (10) The number of common units presented for Mr. Ordemann includes (i) 10,000 phantom units that vested in February 2015, which resulted in the issuance of an equal number of common units, and (ii) 120,000 common unit options that became exercisable in February 2015. (11) The number of common units presented for Ms. Hildebrandt includes 30,000 common unit options that became exercisable in February 2015. Ms. Hildebrandt resigned effective December 31, 2014. (12) Cumulatively, this group's beneficial ownership amount includes (i) 148,125 phantom units that vested in February 2015, which resulted in the issuance of an equal number of common units, and (ii) 670,000 common unit options that became exercisable in February 2015.

Effective January 15, 2015, privately held affiliates of EPCO (together with their respective subsidiaries) have pledged 180,000,000 of our common units that they own as security under such affiliates' credit facilities.

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These credit facilities include customary provisions regarding potential events of default. As a result, a change in ownership of these units could result if an event of default ultimately occurred.

Equity Ownership Guidelines

In order to further align the interests and actions of our general partner's directors and executive officers with our long-term interests and those of our general partner and other unitholders, the Board has adopted and approved certain equity ownership guidelines for our general partner's directors and executive officers. Under these guidelines:

each non-management director of our general partner is required to own Enterprise common units having an aggregate value (as defined in the guidelines) of three times the dollar amount of such non-management director's aggregate annual cash retainer for service on the Board for the most recently completed calendar year; and

§	each executive officer of our general partner is required to own Enterprise common units having an aggregate value (as defined in the guidelines) of three times the dollar amount of such executive officer's aggregate annual base salary for the most recently completed calendar year.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth certain information as of December 31, 2014 regarding the long-term incentive plans of EPCO under which our common units are authorized for issuance. For additional information regarding our equity-based compensation, see Note 5 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Number of

Units

Remaining

Available For

Number of

Future Issuance

Units to

Weighted-

Under Equity

Be Issued

Average

Compensation

Upon Exercise

Exercise Price

Plans (excluding

of Outstanding

securities

Common Unit

reflected in

Plan Category

Options

column (a))

(a)

(b)

(c)

Equity compensation plans approved by unitholders:

1998 Plan (1)

2,748,017

2008 Plan (2,3)

1,270,000

16.14

12,895,605

Equity compensation plans not approved by unitholders:

None

Total for equity compensation plans

1,270,000

16.14

15,643,622

(1) The total number of common units authorized for issuance under the 1998 Plan was 14,000,000 common units.

(2) At December 31, 2014, the total number of common units authorized for issuance under the 2008 Plan was 25,000,000 common units. This amount increased by 5,000,000 common units on January 1, 2015 and will increase by an additional 5,000,000 common units subsequently on each January 1 thereafter during the term of the 2008 Plan; provided, however, that in no event shall the maximum aggregate amount available for issuance under the 2008 Plan exceed 70,000,000 common units.

(3) The 1,270,000 unit option awards outstanding at December 31, 2014 became exercisable in February 2015.

The Enterprise Products 1998 Long-Term Incentive Plan ("1998 Plan") provides for awards of our common units and other rights to our non-management directors and to employees of EPCO and its affiliates providing services to us. Awards under the 1998 Plan may be granted in the form of unit options, restricted common units, phantom units and DERs.

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The 2008 Plan provides for awards of our common units and other rights to our non-management directors and to consultants and employees of EPCO and its affiliates providing services to us. Awards under the 2008 Plan may be granted in the form of unit options, restricted common units, phantom units, UARs, DERs, unit awards and other unit-based awards or substitute awards.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Certain Relationships and Related Transactions

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. Additional information regarding our related party transactions is set forth in Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report and is incorporated by reference into this Item 13.

Review and Approval of Transactions with Related Parties

We consider transactions between us and our subsidiaries and unconsolidated affiliates, on the one hand, and our executive officers and directors (or their immediate family members), our general partner or its affiliates (including other companies owned or controlled by the DD LLC Trustees or the EPCO Trustees), on the other hand, to be related party transactions. As further described below, our partnership agreement sets forth general procedures by which related party transactions and conflicts of interest may be approved or resolved by Enterprise GP or its Audit and Conflicts Committee. In addition, the Audit and Conflicts Committee charter, Enterprise GP's written internal review and approval policies and procedures (referred to as its "management authorization policy") and the amended and restated ASA with EPCO address specific types of related party transactions, as further described below.

At December 31, 2014, the Audit and Conflicts Committee was comprised of three independent directors: Thurmon M. Andress, Charles E. McMahen and Richard S. Snell. In accordance with its charter, the Audit and Conflicts Committee reviews and approves related party transactions:

§	pursuant to our partnership agreement or the limited liability company agreement of Enterprise GP, as such agreements may be amended from time to time;

§	in which an officer or director of Enterprise GP or any of our subsidiaries, or an immediate family member of such an officer or director, has a material financial interest or is otherwise a party;

§	when requested to do so by management or the Board;

§	with a value of $5 million or more (unless such transaction is equivalent to an arm's length or third party transaction); or

§	that it may otherwise deem appropriate from time to time.

The Audit and Conflicts Committee did not review or approve any related party transactions during the year ended December 31, 2014.

Enterprise GP's management authorization policy generally requires Board approval for asset purchase or sales transactions and capital expenditures to the extent such transactions have a value in excess of $250 million. Any such transaction would typically also require Audit and Conflicts Committee review under its charter if such transaction is also a related party transaction.

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As noted previously, all of our management, administrative and operating functions are performed by employees of EPCO (pursuant to an administrative services agreement, or ASA) or by other service providers. The ASA governs numerous day-to-day transactions between us, Enterprise GP and EPCO and its affiliates, including the provision by EPCO of administrative and other services to us and our reimbursement to EPCO of costs, without markup or discount, for those services. The ASA was reviewed, approved and recommended to the Board by our Audit and Conflicts Committee, and the Board also approved it upon receiving such recommendation. For additional information regarding the ASA, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Related party transactions that are outside the scope of the ASA and not reviewed by the Audit and Conflicts Committee are subject to Enterprise GP's management authorization policy. This policy, which applies to related party transactions as well as transactions with third parties, specifies thresholds for our general partner's officers and Board to authorize various categories of transactions, including purchases and sales of assets, commercial and financial transactions and legal agreements.

Partnership Agreement Standards for Audit and Conflicts Committee Review

Under our partnership agreement, whenever a potential conflict of interest exists or arises between Enterprise GP or any of its affiliates, on the one hand, and us, any of our subsidiaries or any partner, on the other hand, any resolution or course of action by Enterprise GP or its affiliates in respect of such conflict of interest is permitted and deemed approved by our limited partners, and will not constitute a breach of our partnership agreement or any agreement contemplated by such agreement, or of any duty stated or implied by law or equity, if the resolution or course of action is or, by operation of the partnership agreement is deemed to be, fair and reasonable to us; provided that, any conflict of interest and any resolution of such conflict of interest will be conclusively deemed fair and reasonable to us if such conflict of interest or resolution is (i) approved by a majority of the members of the Audit and Conflicts Committee (i.e., a "Special Approval" is granted) or (ii) on terms objectively demonstrable to be no less favorable to us than those generally being provided to or available from third parties.

The Audit and Conflicts Committee (in connection with its Special Approval process) may consider the following when resolving conflicts of interest:

§	the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;

§	the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us);

§	any customary or accepted industry practices and any customary or historical dealings with a particular party;

§	any applicable generally accepted accounting or engineering practices or principles;

§	the relative cost of capital of the parties involved and the consequent rates of return to the equity holders of such parties; and

§	such additional factors as the Audit and Conflicts Committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

The level of review and work performed by the Audit and Conflicts Committee with respect to a given transaction varies depending upon the nature of the transaction and the scope of the Audit and Conflicts Committee's obligation. Examples of functions the Audit and Conflicts Committee may, as it deems appropriate, perform in the course of reviewing a transaction include, but are not limited to:

§	assessing the business rationale for the transaction;

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§	reviewing the terms and conditions of the proposed transaction, including consideration and financing requirements, if any;

§	assessing the effect of the transaction on our results of operations, financial condition, cash available for distribution, properties or prospects;

§	conducting due diligence, including interviews and discussions with management and other representatives and reviewing transaction materials and findings of management and other representatives;

§	considering the relative advantages and disadvantages of the transactions to the parties involved;

§	engaging third party financial advisors to provide financial advice and assistance, including fairness opinions if requested;

§	engaging legal advisors; and

§	evaluating and negotiating the transaction and recommending for approval or approving the transaction, as the case may be.

Nothing contained in our partnership agreement requires the Audit and Conflicts Committee to consider the interests of any party other than us. In the absence of the Audit and Conflicts Committee or our general partner acting in bad faith, the resolution, action or terms so made, taken or provided (including granting Special Approval) by the Audit and Conflicts Committee or our general partner with respect to such matter are deemed conclusive and binding on all persons (including all of our limited partners) and do not constitute a breach of partnership agreement, or any other agreement contemplated thereby, or a breach of any standard of care or duty imposed in our partnership agreement or under the Delaware Revised Uniform Limited Partnership Act or any other law, rule or regulation. Our partnership agreement provides that it is presumed that the resolution, action or terms made, taken or provided by the Audit and Conflicts Committee or our general partner were not made, taken or provided in bad faith, and in any proceeding brought by any limited partner or by or on behalf of such limited partner or any other limited partner or us challenging such resolution, action or terms, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Transactions with Director

In August 2014, we purchased right-of-way from a private family corporation, approximately 80% of which is owned by Mr. Snell and members of his immediate family and for which Mr. Snell regularly acts as legal counsel. The total purchase price paid to the family corporation for the right-of-way was approximately $0.3 million and was based on market rates recently paid by us in similar transactions with unaffiliated landowners.

Director Independence

Each of the members of the Audit and Conflicts Committee, namely Messrs. Andress, McMahen and Snell, and two members of the Governance Committee, namely Messrs. Barnett and Hackett, have been determined to be independent under the applicable NYSE listing standards and rules of the SEC. For a discussion of independence standards applicable to our Board and factors considered by our Board in making its independence determinations, please refer to "Partnership Governance" included under Part III, Item 10 of this annual report.

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Item 14. Principal Accountant Fees and Services.

We have engaged Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, "Deloitte & Touche") as our independent registered public accounting firm and principal accountants. The following table summarizes amounts billed to us by Deloitte & Touche for (or in) each of the years presented, as applicable (dollars in millions):

	For the Year Ended December 31,
	2014		2013
Audit Fees (1)	$	4.7	$	4.4
Audit-Related Fees (2)		--		--
Tax Fees (3)		--		--
All Other Fees (4)		--		--

(1) Audit fees represent amounts billed for each of the years presented for (i) the audit of our annual financial statements and internal controls over financial reporting, (ii) the review of our quarterly financial statements filed on Form 10-Q, (iii) standalone audits of our consolidated subsidiaries and (iv) those services normally provided by Deloitte & Touche in connection with our statutory and regulatory filings or engagements, including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this annual report. (2) Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews and are not reported under the section labeled "Audit Fees." No such services were rendered by Deloitte & Touche during the last two years. (3) Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. No such services were rendered by Deloitte & Touche during the last two years. (4) All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above. No such services were rendered by Deloitte & Touche during the last two years.

In order for Deloitte & Touche to maintain its independence, we are prohibited from using them to perform general bookkeeping, management or human resource functions for us, and any other service not permitted by the Public Company Accounting Oversight Board.

The Audit and Conflicts Committee of our general partner has approved the use of Deloitte & Touche as our independent principal accountant. In connection with its oversight responsibilities, the Audit and Conflicts Committee has adopted a pre-approval policy regarding any services to be performed by Deloitte & Touche. The pre-approval policy includes four primary service categories: Audit, Audit-related, Tax and Other.

When Deloitte & Touche's services are required, management and Deloitte & Touche discuss the proposed work with the Audit and Conflicts Committee. These discussions typically address the reasons for the project, the scope of the work to be performed and an estimate of the fee to be charged by Deloitte & Touche for such work. The Audit and Conflicts Committee discusses the request with management and Deloitte & Touche and, if the work is deemed necessary and appropriate for Deloitte & Touche to perform, approves the request subject to the fee estimate presented (the initial "pre-approved" fee amount). If at a later date, it appears that the initial pre-approved fee amount is insufficient to complete the work, management and Deloitte & Touche must present a supplemental request to the Audit and Conflicts Committee to increase the approved amount along with reasons for the increase. Under the pre-approval policy, management cannot act upon its own to authorize an expenditure for Deloitte & Touche services outside of the pre-approved amounts. On a quarterly basis, the Audit and Conflicts Committee is provided a schedule that compares the pre-approved amounts for each primary service category with the actual fees billed for each type of service. We believe the Audit and Conflicts Committee's pre-approval process helps to ensure the independence of our principal accountant from management.

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PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)	The following documents are filed as a part of this annual report:

(1)	Financial Statements: See "Index to Consolidated Financial Statements" beginning on page F-1 of this annual report for the financial statements included herein.

(2)	Financial Statement Schedules: The separate filing of financial statement schedules has been omitted because such schedules are either not applicable or the information called for therein appears in the footnotes of our Consolidated Financial Statements.

(3)

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	Third 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 4.4 to Form 8-K filed October 6, 2004).
4.7	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).
4.8	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).
4.9	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).
4.10	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).
4.11	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).
4.12	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).
4.13	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).
4.14	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).
4.15	Fourteenth Supplemental Indenture, dated as of December 8, 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 4.3 to Form 8-K filed December 8, 2008).
4.16	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).
4.17	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).
4.18	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).

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4.19	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).
4.20	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).
4.21	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).
4.22	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).
4.23	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).
4.24	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).
4.25	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).
4.26	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).
4.27	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).
4.28	Form of Global Note representing $500.0 million principal amount of 5.60% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.29	Form of Global Note representing $150.0 million principal amount of 5.60% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
4.30	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).
4.31	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).
4.32	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).
4.33	Form of Junior Subordinated Note, including Guarantee (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.34	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).

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4.35	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).
4.36	Form of Global Note representing $500.0 million principal amount of 9.75% Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8, 2008).
4.37	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).
4.38	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).
4.39	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).
4.40	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).
4.41	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).
4.42	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).
4.43	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).
4.44	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).
4.45	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).
4.46	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).
4.47	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).
4.48	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).
4.49	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).
4.50	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).
4.51	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).
4.52	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).
4.53	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).

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4.54	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).
4.55	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).
4.56	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).
4.57	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).
4.58	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).
4.59	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).
4.60	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).
4.61	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).
4.62	Replacement Capital Covenant, dated October 27, 2009, among 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).
4.63	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).
4.64	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).
4.65	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).
4.66	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).
4.67	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).
4.68	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).

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4.69	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).
4.70	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).
4.71	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).
4.72	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).
4.73	Replacement of Capital Covenant, dated May 18, 2007, executed by TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P. in favor of the covered debt holders described therein (incorporated by reference to Exhibit 99.1 to the Form 8-K of TEPPCO Partners, L.P. on May 18, 2007).
4.74	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).
4.75	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).
4.76	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).
4.77	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***	Enterprise Products 1998 Long-Term Incentive Plan (Amended and Restated as of February 23, 2010) (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 26, 2010).
10.2***	Form of Employee Restricted Unit Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 10-Q filed August 9, 2010).
10.3***	2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (incorporated by reference to Annex A to Definitive Proxy Statement filed August 26, 2013).
10.4***	Form of Option Grant Award under the 2008 Enterprise Products Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11 to Form 10-Q filed August 9, 2010).
10.5***	Form of Employee Restricted Unit Grant Award under the 2008 Enterprise Products Long-Term Incentive Plan (incorporated by reference to Exhibit 10.13 to Form 10-Q filed August 9, 2010).
10.6***	Form of Employee Phantom Unit Grant Award under the 2008 Enterprise Products Long-Term Incentive Plan for awards issued before February 18, 2015 (incorporated by reference to Exhibit 10.18 to Form 10-K filed March 3, 2014).

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10.7***#	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.
10.8***#	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.
10.9	Distribution Waiver Agreement, dated as of November 22, 2010, by and among Enterprise Products Partners L.P., EPCO Holdings, Inc. and the EPD Unitholder named therein (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 23, 2010).
10.10	Revolving Credit Agreement, dated as of September 7, 2011, among Enterprise Products Operating LLC, Canadian Enterprise Gas Products, Ltd, the Lenders party thereto, Wells Fargo Bank National Association, as Administrative Agent, The Royal Bank of Scotland PLC, Mizuho Corporate Bank, Ltd. and The Bank of Nova Scotia, as Co-syndication Agents and JPMorgan Chase Bank, N.A. and Barclays Bank PLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 8, 2011).
10.11	Guaranty Agreement, dated as of September 7, 2011, by and among Enterprise Products Partners L.P. and Enterprise Products Operating LLC in favor of Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed September 8, 2011).
10.12	First Amendment dated as of June 19, 2013 to Revolving Credit Agreement dated as of September 7, 2011, among Enterprise Products Operating LLC, Canadian Enterprise Gas Products, Ltd., Wells Fargo Bank, National Association, as administrative agent for each of the lenders that is a signatory or which becomes a signatory to the Credit Agreement, the Lenders party thereto, Citibank, N.A., DNB Bank ASA, New York Branch, JPMorgan Chase Bank, N.A., Mizuho Corporate Bank, Ltd. and The Royal Bank of Scotland Plc, as Co-Syndication Agents, and The Bank of Nova Scotia, SunTrust Bank, The Bank of Tokyo-Mitsubishi UFJ, Ltd., UBS Securities LLC and Royal Bank of Canada, as Co-Documentation Agents, and Wells Fargo Securities, LLC, Citigroup Global Markets Inc., DNB Markets, Inc., J.P. Morgan Securities LLC, Mizuho Corporate Bank, Ltd., RBS Securities Inc., Scotia Capital, SunTrust Robinson Humphrey, Inc., and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.3 to Form 8-K filed on June 20, 2013).
10.13	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).
10.14	Equity Distribution Agreement, dated November 12, 2013, by and among Enterprise Products Partners L.P., Enterprise Products OLPGP, Inc., Enterprise Products Operating LLC and Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., J.P Morgan Securities LLC, Mitsubishi UFJ Securities (USA), Inc., Mizuho Securities USA Inc., Morgan Stanley & Co. LLC, Raymond James & Associates, Inc., RBC Capital Markets, LLC, Scotia Capital (USA) Inc., SunTrust Robinson Humphrey, Inc., UBS Securities LLC and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 1.1 to Form 8-K filed November 12, 2013).
10.15	364-Day Revolving Credit Agreement, dated as of September 30, 2014, among Enterprise Products Operating LLC, the Lenders party thereto, Citibank, N.A., as Administrative Agent, certain financial institutions from time to time named therein, as Co-Documentation Agents and Citibank, N.A. as Sole Lead Arranger and Sole Book Runner (incorporated by reference to Exhibit 10.1 to Form 8-K filed on October 1, 2014).
10.16	Guaranty Agreement, dated as of September 30, 2014, by Enterprise Products Partners L.P. in favor of Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed on October 1, 2014).
10.17	Liquidity Option Agreement, dated as of October 1, 2014, between Enterprise Products Partners, L.P., Oiltanking Holding Americas, Inc., and Marquard & Bahls AG (incorporated by reference to Exhibit 10.3 to Form 8-K filed on October 1, 2014).

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10.18	Support Agreement, dated as of November 11, 2014, by and among Enterprise Products Partners L.P., Enterprise Products Operating LLC and Oiltanking Partners, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 12, 2014).
10.19***#	Agreement and Release, dated effective as of December 31, 2014, by and among and Stephanie C. Hildebrandt and Enterprise Products Company.
12.1#	Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2014, 2013, 2012, 2011 and 2010.
21.1#	List of consolidated subsidiaries as of February 1, 2015.
23.1#	Consent of Deloitte & Touche LLP.
31.1#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P.'s annual report on Form 10-K for the year ended December 31, 2014.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.'s annual report on Form 10-K for the year ended December 31, 2014.
32.1#	Sarbanes-Oxley Section 906 certification of Michael A. Creel for Enterprise Products Partners L.P.'s annual report on Form 10-K for the year ended December 31, 2014.
32.2#	Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.'s annual report on Form 10-K for the year ended December 31, 2014.
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

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file numbers for Enterprise Products Partners L.P., Enterprise GP Holdings L.P, TEPPCO Partners, L.P. and TE Products Pipeline Company, LLC are 1-14323, 1-32610, 1-10403 and 1-13603, respectively.
***	Identifies management contract and compensatory plan arrangements.
#	Filed with this report.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on March 2, 2015.

ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)

By:	Enterprise Products Holdings LLC, as General Partner


By:	/s/ Michael J. Knesek
Name:	Michael J. Knesek
Title:	Senior Vice President, Controller and Principal Accounting Officer of the General Partner

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on March 2, 2015.

Signature		Title (Position with Enterprise Products Holdings LLC)
/s/ Randa Duncan Williams		Director and Chairman of the Board
Randa Duncan Williams
/s/ Thurmon M. Andress		Director
Thurmon M. Andress
/s/ E. William Barnett		Director
E. William Barnett
/s/ Michael A. Creel		Director and Chief Executive Officer
Michael A. Creel
/s/ Dr. F. Christian Flach		Director
Dr. F. Christian Flach
/s/ W. Randall Fowler		Director, Executive Vice President and Chief Financial Officer
W. Randall Fowler
/s/ James T. Hackett		Director
James T. Hackett
/s/ Charles E. McMahen		Director
Charles E. McMahen
/s/ Richard S. Snell		Director
Richard S. Snell
/s/ A. James Teague		Director and Chief Operating Officer
A. James Teague
/s/ Michael J. Knesek		Senior Vice President, Controller and Principal Accounting Officer
Michael J. Knesek

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Item 8. Financial Statements and Supplementary Data.

ENTERPRISE PRODUCTS PARTNERS L.P.

INDEX TO FINANCIAL STATEMENTS

		Page No.
Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2014 and 2013		F-3

Statements of Consolidated Operations for the Years Ended December 31, 2014, 2013 and 2012		F-4

Statements of Consolidated Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012		F-5

Statements of Consolidated Cash Flows for the Years Ended December 31, 2014, 2013 and 2012		F-6

Statements of Consolidated Equity for the Years Ended December 31, 2014, 2013 and 2012		F-7

Notes to Consolidated Financial Statements
	Note 1 – Partnership Operations, Organization and Basis of Presentation	F-8
	Note 2 – Summary of Significant Accounting Policies	F-9
	Note 3 – Recent Accounting Developments	F-15
	Note 4 – Revenue Recognition	F-15
	Note 5 – Equity-based Awards	F-18
	Note 6 – Derivative Instruments, Hedging Activities and Fair Value Measurements	F-22
	Note 7 – Inventories	F-33
	Note 8 – Property, Plant and Equipment	F-34
	Note 9 – Investments in Unconsolidated Affiliates	F-36
	Note 10 – Acquisition of Oiltanking Partners, L.P.	F-40
	Note 11 – Intangible Assets and Goodwill	F-44
	Note 12 – Debt Obligations	F-50
	Note 13 – Equity and Distributions	F-54
	Note 14 – Business Segments	F-59
	Note 15 – Related Party Transactions	F-65
	Note 16 – Provision for Income Taxes	F-67
	Note 17 – Earnings Per Unit	F-69
	Note 18 – Commitments and Contingencies	F-70
	Note 19 – Significant Risks and Uncertainties	F-75
	Note 20 – Supplemental Cash Flow Information	F-77
	Note 21 – Quarterly Financial Information (Unaudited)	F-78
	Note 22 – Condensed Consolidating Financial Information	F-79

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Enterprise Products Holdings LLC and

Unitholders of Enterprise Products Partners L.P.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Enterprise Products Partners L.P. and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related statements of consolidated operations, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Enterprise Products Partners L.P. and subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2015, expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 2, 2015

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ENTERPRISE PRODUCTS PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

	December 31,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	74.4		$	56.9
Restricted cash		--			65.6
Accounts receivable – trade, net of allowance for doubtful accounts of $13.9 at December 31, 2014 and $7.5 at December 31, 2013		3,823.0			5,475.5
Accounts receivable – related parties		2.8			6.8
Inventories		1,014.2			1,093.1
Prepaid and other current assets		576.3			325.5
Total current assets		5,490.7			7,023.4
Property, plant and equipment, net		29,881.6			26,946.6
Investments in unconsolidated affiliates		3,042.0			2,437.1
Intangible assets, net of accumulated amortization of $1,246.3 at December 31, 2014 and $1,150.0 at December 31, 2013		4,302.1			1,462.2
Goodwill (see Note 11)		4,199.9			2,080.0
Other assets		184.4			189.4
Total assets	$	47,100.7		$	40,138.7

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 12)	$	2,206.4		$	1,125.0
Accounts payable – trade		773.8			723.7
Accounts payable – related parties		118.9			150.5
Accrued product payables		3,853.3			5,608.7
Accrued interest		335.5			304.3
Other current liabilities		585.8			326.5
Total current liabilities		7,873.7			8,238.7
Long-term debt (see Note 12)		19,157.4			16,226.5
Deferred tax liabilities		66.6			60.8
Other long-term liabilities		310.8			172.3
Commitments and contingencies (see Note 18)
Equity: (see Note 13)
Partners' equity:
Limited partners:
Common units (1,937,324,817 units outstanding at December 31, 2014 and 1,871,370,016 units outstanding at December 31, 2013)		18,304.8			15,573.8
Accumulated other comprehensive loss		(241.6	)		(359.0	)
Total partners' equity		18,063.2			15,214.8
Noncontrolling interests		1,629.0			225.6
Total equity		19,692.2			15,440.4
Total liabilities and equity	$	47,100.7		$	40,138.7

See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED OPERATIONS

(Dollars in millions, except per unit amounts)

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

Earnings per unit: (see Note 17)
Basic earnings per unit	$	1.51		$	1.45		$	1.40
Diluted earnings per unit	$	1.47		$	1.41		$	1.35

See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Dollars in millions)

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

See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in millions)

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

See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

STATEMENTS OF CONSOLIDATED EQUITY

(See Note 13 for Unit History, Accumulated Other Comprehensive

Income (Loss) and Noncontrolling Interests)

(Dollars in millions)

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

See Notes to Consolidated Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

With the exception of per unit amounts, or as noted within the context of each disclosure,

the dollar amounts presented in the tabular data within these disclosures are

stated in millions of dollars.

KEY REFERENCES USED IN THESE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In addition to owning our general partner, EPCO and its privately held affiliates owned approximately 35.3% of our limited partner interests at December 31, 2014.

References to "TEPPCO" mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009 (the "TEPPCO Merger").

Note 1. Partnership Operations, Organization and Basis of Presentation

General

Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States ("U.S."), Canada and Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations currently include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminals (including liquefied petroleum gas or "LPG"); crude oil gathering, transportation, storage and terminals; offshore production platforms; petrochemical and refined products transportation, storage and terminals, and related services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

systems and in the Gulf of Mexico. Our assets include approximately 51,300 miles of onshore and offshore pipelines; 225 million barrels ("MMBbls") of storage capacity for NGLs, petrochemicals, refined products and crude oil; and 14 billion cubic feet ("Bcf") of natural gas storage capacity. In addition, our asset portfolio includes 24 natural gas processing plants, 22 NGL and propylene fractionators, six offshore hub platforms located in the Gulf of Mexico, a butane isomerization complex, NGL import and LPG export terminals, a refined products export terminal and octane enhancement and high-purity isobutylene production facilities.

We conduct substantially all of our business through EPO and are owned 100% by our limited partners from an economic perspective. Enterprise GP manages our partnership and owns a non-economic general partner interest in us. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the "ASA") or by other service providers. See Note 15 for information regarding the ASA and other related party matters.

As a result of our acquisition of Oiltanking GP on October 1, 2014, we began consolidating the financial statements of Oiltanking and its general partner as of the acquisition date. See Note 10 for information regarding this acquisition.

See Note 13 for information regarding a two-for-one common unit split completed on August 21, 2014. All per unit amounts and number of units outstanding in these Consolidated Financial Statements and Notes thereto are presented on a post-split basis.

Note 2. Summary of Significant Accounting Policies

Allowance for Doubtful Accounts

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash and Cash Equivalents

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

Consolidation Policy

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

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

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

Contingencies

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Current Assets and Current Liabilities

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

Derivative Instruments

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

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

Earnings Per Unit

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

Environmental Costs

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Equity-based Awards

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

Estimates

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

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

Impairment Testing for Goodwill

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

Impairment Testing for Long-Lived Assets

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

Impairment Testing for Unconsolidated Affiliates

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

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Income Taxes

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

Inventories

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

Other Non-Operating Income

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

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

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

Property, Plant and Equipment

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

Restricted Cash

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

Revenue Recognition

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

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Note 3. Recent Accounting Developments

identify the contract;

identify the performance obligations in the contract;

determine the transaction price;

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

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

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

Note 4. Revenue Recognition

The following information summarizes our revenue recognition policies by business segment. See Note 14 for general information regarding our business segments.

NGL Pipelines & Services

In our natural gas processing business, we utilize contracts that are either fee-based, commodity-based or a combination of the two. When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer's natural gas has been processed and redelivered. Our commodity-based contracts include keepwhole and margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts and contracts featuring a combination of commodity and fee-based terms. Under keepwhole and margin-band contracts, we take ownership of mixed NGLs extracted from the producer's natural gas stream while replacing the equivalent quantity of energy on a natural gas basis to producers. We recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. Under percent-of-liquids contracts, we take ownership of a portion of the mixed NGLs extracted from the producer's natural gas stream (in lieu of a cash processing fee) and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. Under percent-of-proceeds contracts, we share in the proceeds generated from the sale of mixed NGLs we extract on the producer's behalf (in lieu of a cash processing fee). In certain cases, we also utilize contracts that include a combination of commodity-based terms (such as those described above) and fee-based terms.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenues from NGL pipeline transportation contracts and tariffs are generally based upon a fixed fee per gallon of liquids transported multiplied by the volume delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission ("FERC"), or contractual arrangements. Typically, pipeline transportation revenue is recognized when volumes are transported and delivered. However, under certain NGL pipeline transportation agreements (e.g., those associated with committed shippers on our Texas Express Pipeline, Front Range Pipeline, ATEX and Aegis Ethane Pipeline) customers are required to ship a minimum volume over an agreed-upon period. These arrangements typically entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper "make-up rights"). Revenue pursuant to such agreements, including that associated with make-up rights, is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation.

We collect storage revenue under our NGL and related product storage contracts primarily from capacity reservation agreements, where we collect a fee for reserving storage capacity for customers in our underground storage wells. Customers pay reservation fees based on the level of storage capacity reserved rather than the actual volumes stored. Under these agreements, revenue is recognized ratably over the specified reservation period. When a customer exceeds its reserved capacity, we charge that customer excess storage fees, which are recognized in the period of occurrence. In addition, we generally charge customers throughput fees based on volumes delivered into and subsequently withdrawn from storage, which are recognized as the service is provided.

We typically earn revenues from NGL fractionation under fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., natural gas fuel costs). Under fee-based arrangements, revenue is recognized in the period services are provided. At our Norco facility in Louisiana, we perform fractionation services for certain customers under percent-of-liquids contracts. Such contracts allow us to retain a contractually determined percentage of the customer's fractionated NGLs as payment for services rendered. Revenue is recognized from such arrangements when we sell and deliver the retained NGLs to customers.

Revenue from NGL import and LPG export terminaling activities is recorded in the period services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded.

Onshore Natural Gas Pipelines & Services

Our onshore natural gas pipelines typically generate revenues from transportation agreements under which shippers are billed a fee per unit of volume transported multiplied by the volume gathered or delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. Certain of our onshore natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved (whether or not the shipper actually utilizes such capacity). Revenues are recognized when volumes have been delivered to customers or in the period we provide firm capacity reservation services.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Under our natural gas storage revenue contracts, there are typically two components: (i) monthly demand payments, which are associated with a customer's storage capacity reservation and paid regardless of actual usage, and (ii) storage fees per unit of volume stored at our facilities. Revenue from demand payments is recognized during the period the customer reserves capacity. Revenue from storage fees is recognized in the period the services are provided.

Our natural gas marketing activities generate revenue from the sale and delivery to local gas distribution companies and other customers of natural gas purchased from producers, regional natural gas processing plants and the open market. Revenue from these sales contracts is recognized when natural gas is delivered to customers. In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location.

Onshore Crude Oil Pipelines & Services

Revenue from crude oil transportation is generally based upon a fixed fee per barrel transported multiplied by the volume delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. Typically, revenue associated with these arrangements is recognized when volumes are transported and delivered; however, under certain of our crude oil pipeline transportation agreements, customers are required to ship a minimum volume over an agreed-upon period, with make-up rights. Revenue pursuant to such agreements, including that associated with make-up rights, is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper's ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation.

Under our crude oil terminaling agreements, we charge customers for crude oil storage based on storage capacity reservation agreements, where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized ratably over the specified reservation period. In addition, we charge our customers throughput (or "pumpover") fees based on volumes withdrawn from our terminals. Revenue is also generated from fee-based trade documentation services and is recognized as services are completed.

Our crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or from others on the open market. These sales contracts generally settle with the physical delivery of crude oil to customers. In general, the sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location, timing or crude oil quality.

Offshore Pipelines & Services

Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume gathered or transported multiplied by the volume delivered. Transportation fees are based either on contractual arrangements or tariffs regulated by the FERC. Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered.

Revenues from offshore platform services generally consist of demand fees and commodity charges. Revenues from offshore platform services are recognized in the period the services are provided. Demand fees represent charges to customers served by our offshore platforms regardless of the volume the customer actually delivers to the platform. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform multiplied by the total volume of each product delivered. Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Petrochemical & Refined Products Services

Our propylene fractionation, butane isomerization and deisobutanizer facilities generate revenue through fee-based arrangements, which typically include a base-processing fee subject to adjustment for changes in power, fuel and labor costs, all of which are the primary costs of propylene fractionation and butane isomerization. Our butane isomerization and deisobutanizer operations also generate revenue from the sale and delivery of by-products. Revenue resulting from such agreements is recognized in the period the services are provided. Revenues from our petrochemical pipeline transportation contracts are primarily based upon a fixed fee per volume transported (typically measured in gallons or pounds) multiplied by the volume delivered.

Our petrochemical marketing activities include the purchase and fractionation of refinery grade propylene obtained in the open market and generate revenues from the sale and delivery of products obtained through propylene fractionation. Revenue from these sales contracts is recognized when such products are delivered to customers. In general, we sell our petrochemical products at market-based prices, which may include pricing differentials for factors such as delivery location. Revenue from the production and sale of octane additives and high purity isobutylene is dependent on the sales price and volume of such commodities sold to customers. Revenue is recognized for sales transactions when the product is delivered.

Pipelines transporting refined products generate revenues through contracts and tariffs as customers are billed a fixed fee per barrel of liquids transported multiplied by the volume delivered. The fees charged under these arrangements are either contractual or regulated by governmental agencies, including the FERC. Revenue associated with these fee-based contracts and tariffs is recognized when volumes have been delivered. Revenue from our refined products storage facilities is based on capacity reservation agreements where we collect a fee for reserving a defined storage capacity for customers at our facilities. Under these contracts, revenue is recognized ratably over the length of the storage period. Revenue from product terminaling activities is recorded in the period such services are provided. Customers are typically billed a fee per unit of volume loaded.

Revenue is also generated from the provision of inland and offshore marine transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil, liquefied petroleum gas and other petroleum products via tow boats and tank barges. Under our marine services transportation contracts, revenue is recognized over the transit time of individual tows as determined on an individual contract basis, which is generally less than ten days in duration. Revenue from these contracts is typically based on set day rates or a set fee per cargo movement. The costs of fuel, substantially all of which is a pass through expense, and other specified operational fees and costs are directly reimbursed by the customer under most of these contracts.

Note 5. Equity-based Awards

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

Restricted Common Unit Awards

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

Unit Option Awards

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

Phantom Unit Awards

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

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

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

§	Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change.

§	Variable cash flows of a forecasted transaction – In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income (loss) and is reclassified into earnings when the forecasted transaction affects earnings.

An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Any ineffectiveness associated with a hedge relationship is recognized in earnings immediately. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings.

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

Interest Rate Hedging Activities

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Commodity Hedging Activities

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

(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Derivative Instruments and Related Hedged Items

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Fair Value Measurements

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Recurring Fair Value Measurements

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nonrecurring Fair Value Measurements

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

Other Fair Value Information

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

Note 7. Inventories

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Note 8. Property, Plant and Equipment

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

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

(1) Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) Platforms and facilities include offshore platforms and related facilities and other associated assets located in the Gulf of Mexico. (4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years. (7) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Asset Retirement Obligations

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9. Investments in Unconsolidated Affiliates

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

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

NGL Pipelines & Services

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

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

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

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

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

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

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

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

Onshore Natural Gas Pipelines & Services

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

Onshore Crude Oil Pipelines & Services

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

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

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

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

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

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

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Offshore Pipelines & Services

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

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

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

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

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

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

Petrochemical & Refined Products Services

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

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

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

Other Investments

Liquidation of Investment in Energy Transfer Equity

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Equity Earnings and Excess Cost

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

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

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

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

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

Note 11. Intangible Assets and Goodwill

Identifiable Intangible Assets

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

In general, our intangible assets fall within two categories – customer relationship and contract-based intangible assets. The values assigned to such intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits of associated resource bases are estimated to be consumed or otherwise used, as appropriate.

Customer relationship intangible assets. Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations and asset purchases whereby (i) we acquired information about or access to customers and now have the ability to provide services to them and (ii) the customers now have the ability to make direct contact with us. Customer relationships may arise from contractual arrangements (such as service contracts) and through means other than contracts, such as through regular contact by sales or service representatives.

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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



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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Goodwill

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 12. Debt Obligations

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Parent-Subsidiary Guarantor Relationships

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

EPO Debt Obligations

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Letters of Credit

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

Lender Financial Covenants

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

Information Regarding Variable Interest Rates Paid

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 13. Equity and Distributions

Partners Equity

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accumulated Other Comprehensive Loss

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

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

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

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

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

Noncontrolling Interests

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

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

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

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

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

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

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

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

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

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

Cash Distributions

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

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

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

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

Note 14. Business Segments

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

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

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

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

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

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

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by our executive management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income.

In total, gross operating margin represents operating income exclusive of (1) depreciation, amortization and accretion expenses, (2) impairment charges, (3) gains and losses attributable to asset sales and insurance recoveries and (4) general and administrative costs. Gross operating margin includes equity in income of unconsolidated affiliates and non-refundable deferred transportation revenues relating to the make-up rights of committed shippers associated with certain pipelines. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions. In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests.

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Note 15. Related Party Transactions

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

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

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

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

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

Relationship with EPCO and Affiliates

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Relationships with Unconsolidated Affiliates

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

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

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

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

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

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

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

Note 16. Provision for Income Taxes

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Note 17. Earnings Per Unit

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

Diluted earnings per unit is computed by dividing net income or loss attributable to our limited partners by the sum of (i) the weighted-average number of our distribution-bearing units outstanding during a period (as used in determining basic earnings per unit), (ii) the weighted-average number of our Class B units (see Note 13) outstanding during a period, (iii) the weighted-average number of Designated Units outstanding during a period and (iv) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the "incremental option units").

In a period of net losses, the Class B units, Designated Units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect. The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase common units at an average market price during the period. The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.

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

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

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

Basic earnings per unit	$	1.51		$	1.45	$	1.40

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

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

Diluted earnings per unit	$	1.47		$	1.41	$	1.35

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

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Note 18. Commitments and Contingencies

Litigation

As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the partnership in litigation matters.

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

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

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

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

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

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Redelivery Commitments

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

Commitments Under Equity Compensation Plans of EPCO

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

Contractual Obligations

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

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

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

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

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

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

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

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

Purchase Obligations. We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (i.e., unconditional) on us that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We classify our unconditional purchase obligations into the following categories:

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

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

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

Other Long-Term Liabilities

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Liquidity Option Agreement

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Centennial guarantees

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

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

Note 19. Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

Our operations are within the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, refined products and certain petrochemicals. We also market natural gas, NGLs, crude oil and other hydrocarbon products. A reduction in demand for our processing, transportation or other midstream services by domestic producers, whether because of low prices for crude oil, NGLs, natural gas or other reasons that negatively impact upstream production activity, could adversely affect our financial position, results of operations and cash flows. In addition, a reduction in demand for natural gas, NGLs, crude oil, refined products, petrochemicals and other hydrocarbon products by the petrochemical, refining or heating industries, whether because of general economic conditions; reduced demand by customers; increased competition from other products due to pricing differences; adverse weather conditions; government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline; or for other reasons, could adversely affect our financial position, results of operations and cash flows.

Credit Risk Due to Industry Concentrations

A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions. We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults. Our largest non-affiliated customer for 2014 was Shell, which accounted for 8.5% of our consolidated revenues for this period.

Counterparty Risk with Respect to Derivative Instruments

In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty's financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral for such transactions nor do we currently anticipate nonperformance by our counterparties.

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Insurance Matters

Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to a fire). Some of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired asset(s).

In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Consolidated Balance Sheets and presented as "Capital expenditures" on our Statements of Consolidated Cash Flows.

Currently, EPCO's deductibles for property damage claims range from $5.0 million to $60.0 million depending on the nature of the loss (windstorm or non-windstorm) and the assets involved (onshore or offshore assets). We continue to maintain business interruption coverage for our onshore and offshore assets, except for those situations involving windstorm-related downtime for our offshore assets.

Due to the high cost of windstorm insurance coverage for our offshore Gulf of Mexico assets, we elected to self-insure these assets during the annual policy period extending from June 2013 to June 2014. We continue to self-insure these assets for the current annual policy period, which extends from June 2014 to June 2015. Although EPCO's current insurance program does not provide any windstorm coverage for our offshore assets, producers affiliated with our Independence Hub and Marco Polo platforms continue to provide certain levels of physical damage windstorm coverage for each of these offshore assets.

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Note 20. Supplemental Cash Flow Information

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

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

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

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

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Note 21. Quarterly Financial Information (Unaudited)

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

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

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

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22. Condensed Consolidating Financial Information

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

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

Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2014

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

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

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Enterprise Products Partners L.P.

Condensed Consolidating Balance Sheet

December 31, 2013

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

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2014

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

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2013

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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2012

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

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Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2014

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

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2013

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

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Comprehensive Income

For the Year Ended December 31, 2012

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

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Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2014

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

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Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2013

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

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Table of Contents

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Enterprise Products Partners L.P.

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2012

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

F-86