EPD 10-K Fiscal year ended Dec. 31, 2023

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

1100 Louisiana Street, 10th Floor , Houston , Texas 77002

(Address of Principal Executive Offices, including Zip Code)

( 713 ) 381-6500

(Registrant’s Telephone Number, including Area Code)

Title of Each Class	Trading Symbol(s)	Name of Each Exchange On Which Registered
Common Units	EPD	New York Stock Exchange

		Page
		Number
PART I
Items 1 and 2 .	Business and Properties.	3
Item 1A.	Risk Factors.	33
Item 1B.	Unresolved Staff Comments.	56
Item 1C.	Cybersecurity	56
Item 3.	Legal Proceedings.	58
Item 4.	Mine Safety Disclosures.	58
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.	59
Item 6.	Reserved.	60
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	60
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	89
Item 8.	Financial Statements and Supplementary Data.	91
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	91
Item 9A.	Controls and Procedures.	91
Item 9B.	Other Information.	94
Item 9C.	Disclosure Regarding Foreign Jurisdictions That Prevent Inspections.	94
PART III
Item 10.	Directors, Executive Officers and Partnership Governance.	94
Item 11.	Executive Compensation.	105
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.	114
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	117
Item 14.	Principal Accountant Fees and Services.	120
PART IV
Item 15.	Exhibits, Financial Statement Schedules.	121
Item 16.	Form 10-K Summary.	130
Signatures		131

/d	=	per day	MMBPD	=	million barrels per day
BBtus	=	billion British thermal units	MMBtus	=	million British thermal units
Bcf	=	billion cubic feet	MMcf	=	million cubic feet
BPD	=	barrels per day	MWac	=	megawatts, alternating current
MBPD	=	thousand barrels per day	MWdc	=	megawatts, direct current
MMBbls	=	million barrels	TBtus	=	trillion British thermal units

•

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

•

NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane);

•

crude oil gathering, transportation, storage, and marine terminals;

•

propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;

•

petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and

•

a marine transportation business that operates on key U.S. inland and intracoastal waterway systems.

•

capitalize on expected trends and opportunities in all energy supply and demand cycles to provide value added services to our customers;

•

maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary assets that enhance our overall value chain; and

•

share capital costs and risks through business ventures or alliances with strategic partners, including those that provide incremental volumes on our systems.

•

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 for heating, as an engine and industrial fuel, and as a petrochemical feedstock in the production of ethylene and propylene.

•

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, diluent in crude oil to aid in transportation, and as a petrochemical feedstock.

					Net Gas	Total Gas
		Production		No. of	Processing	Processing
		Region	Ownership	Processing	Capacity	Capacity
Description of Asset	Location	Served	Interest	Trains (1)	(MMcf/d)	(MMcf/d) (2)
Rocky Mountains
Meeker	Colorado	Piceance	100.0%	2	1,600	1,600
Pioneer	Wyoming	Green River	100.0%	2	1,100	1,100
Chaco	New Mexico	San Juan	100.0%	2	700	700
South Texas
Yoakum	Texas	Eagle Ford	100.0%	3	900	900
Thompsonville	Texas	Eagle Ford	100.0%	1	330	330
Shoup	Texas	Eagle Ford	100.0%	1	280	280
Armstrong	Texas	Eagle Ford	100.0%	2	250	250
San Martin	Texas	Eagle Ford	100.0%	1	200	200
Sonora	Texas	Strawn	100.0%	3	90	90
Delaware Basin
Orla	Texas	Delaware	100.0%	3	900	900
Mentone	Texas	Delaware	100.0%	2	600	600
South Eddy	New Mexico	Delaware	100.0%	1	200	200
Waha	Texas	Delaware	100.0%	1	150	150
Chaparral	New Mexico	Delaware	100.0%	1	40	40
Midland Basin
Poseidon	Texas	Midland	100.0%	1	300	300
Newberry	Texas	Midland	100.0%	2	260	260
Leiker	Texas	Midland	100.0%	1	200	200
Trident	Texas	Midland	100.0%	1	200	200
Taylor	Texas	Midland	100.0%	1	200	200
Louisiana and Mississippi
Pascagoula	Mississippi	Gulf of Mexico	75.0%   (3)	2	750	1,000
Neptune	Louisiana	Gulf of Mexico	66.0%   (4)	2	429	650
Venice	Louisiana	Gulf of Mexico	13.1%   (5)	2	98	750
Carthage
Bulldog	Texas	Cotton Valley	100.0%	1	200	200
Panola	Texas	Cotton Valley	100.0%	1	120	120
Other
Indian Springs	Texas	Wilcox-Woodbine	75.0%   (4)	1	75	100
Total					10,172	11,320

(1)	Each of our natural gas processing assets is comprised of one or more natural gas processing units (referred to as “processing trains”) that are available to handle unprocessed natural gas delivered to each facility.  The nameplate capacity of each processing train will vary.
(2)	Total gas processing capacity represents the combined nameplate processing capacity of all processing trains at each facility.  Actual processing capacity may differ from nameplate processing capacity due to multiple factors including items such as compression limitations, and quality and composition of the gas being processed.
(3)	We own a 75% consolidated interest in the Pascagoula facility through our majority owned subsidiary, Pascagoula Gas Processing LLC.
(4)	We proportionately consolidate our undivided interests in these operating assets.
(5)	Our 13.1% ownership in Venice is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C.

			Pipeline
		Ownership	Length
Description of Asset	Location(s)	Interest	(Miles)
Mid-America Pipeline System (1)	Midwest and Western U.S.	100.0%	7,850
South Texas NGL Pipeline System	Texas	100.0%	1,957
Dixie Pipeline (1)	South and Southeastern U.S.	100.0%	1,300
Seminole NGL Pipeline (1)	Texas	100.0%	1,245
ATEX (1)	Texas to Midwest and Northeast U.S.	100.0%	1,224
Chaparral NGL System	Texas, New Mexico	100.0%	1,080
Louisiana Pipeline System (1)	Louisiana	100.0%	874
Shin Oak NGL Pipeline	Texas	67.0% (3)	668
Texas Express Pipeline (1)	Texas	35.0% (4)	593
Skelly-Belvieu Pipeline (1)	Texas, Oklahoma	50.0% (5)	572
Front Range Pipeline (1)	Colorado, Oklahoma, Texas	33.3% (6)	452
Houston Ship Channel Pipeline System	Texas	100.0%	304
Panola Pipeline (1)	Texas	55.0% (7)	253
Rio Grande Pipeline (1)	Texas	100.0%	248
Aegis Ethane Pipeline (1)	Texas, Louisiana	100.0%	232
Lou-Tex NGL Pipeline (1)	Texas, Louisiana	100.0%	209
Promix NGL Gathering System	Louisiana	50.0% (8)	191
Tri-States NGL Pipeline (1)	Alabama, Mississippi, Louisiana	83.3% (9)	168
Texas Express Gathering System	Texas	45.0% (10)	138
Others (nine systems) (2)	Various	Various (11)	523
Total			20,081

(1)	Interstate transportation services provided on these liquids pipelines, in whole or part, are regulated by federal governmental agencies.
(2)	Includes our Belle Rose and Wilprise pipelines located in the coastal regions of Louisiana; two pipelines located near Port Arthur in southeast Texas; our San Jacinto pipeline located in East Texas; our Permian NGL lateral pipelines located in New Mexico; Leveret pipeline in West Texas and New Mexico; Enterprise Ethane Pipeline in Texas; and a pipeline in Colorado associated with our Meeker facility.  Transportation services provided on the Wilprise and Leveret pipelines are regulated by federal governmental agencies.
(3)	We own a 67% consolidated interest in the Shin Oak NGL Pipeline through our majority owned subsidiary, Breviloba, LLC.
(4)	Our 35% ownership interest in the Texas Express Pipeline is held indirectly through our equity method investment in Texas Express Pipeline LLC.
(5)	Our 50% ownership interest in the Skelly-Belvieu Pipeline is held indirectly through our equity method investment in Skelly-Belvieu Pipeline Company, L.L.C.
(6)	Our 33.3% ownership interest in the Front Range Pipeline is held indirectly through our equity method investment in Front Range Pipeline LLC.
(7)	We own a 55% consolidated interest in the Panola Pipeline through our majority owned subsidiary, Panola Pipeline Company, LLC (“Panola”).  On February 16, 2024, an affiliate of Enterprise entered into a definitive agreement to acquire additional equity interests in Panola.  For more information, see Note 20 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report.
(8)	Our 50% ownership interest in the Promix NGL Gathering System is held indirectly through our equity method investment in K/D/S Promix, L.L.C.
(9)	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.
(10)	Our 45% ownership interest in the Texas Express Gathering System is held indirectly through our equity method investment in Texas Express Gathering LLC.
(11)	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.

•

The Mid-America Pipeline System is an NGL pipeline system consisting of the 3,111-mile Rocky Mountain pipeline, the 2,020-mile Conway North pipeline, the 628-mile Ethane-Propane (“EP”) Mix pipeline, and the 2,091-mile Conway South pipeline.  The Rocky Mountain pipeline transports mixed NGLs from production fields located in the Rocky Mountain Overthrust and San Juan Basin 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 provide buyers and sellers with a centralized location for the storage and pricing of products, while also providing connections to intrastate and/or interstate pipelines.  The EP Mix segment transports EP mix from the Conway hub to petrochemical plants in Iowa and Illinois.  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 NGL Pipeline and Hobbs NGL fractionation and storage facility.  The Mid-America Pipeline System is also connected to 18 non-regulated NGL terminals, 17 of which we own and operate.

•

The South Texas NGL Pipeline System is a network of NGL gathering and transportation pipelines located in South Texas that gather and transport mixed NGLs from natural gas processing facilities (owned by either us or third parties) to our NGL fractionators located in South Texas and in Chambers County, 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 other NGL pipelines and to our Chambers County storage complex.  The South Texas NGL Pipeline System extends our ethane header system from Chambers County, Texas to Corpus Christi, Texas.

•

The Dixie Pipeline transports propane and other NGLs from locations in southeast Texas, south Louisiana and Mississippi to markets in the southeastern U.S.  The Dixie Pipeline 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 Appalachia-to-Texas Express, or ATEX , pipeline transports ethane in southbound service from third-party owned NGL fractionation plants located in Ohio, Pennsylvania and West Virginia to our Chambers County storage complex.  Ethane originating at these fractionation facilities is sourced from the Marcellus and Utica Shale production areas.  ATEX operates in nine states: Arkansas, Illinois, Indiana, Louisiana, Missouri, Ohio, Pennsylvania, Texas and West Virginia.

•

The Chaparral NGL System transports mixed NGLs from natural gas processing facilities located in West Texas and New Mexico to interconnects with our NGL pipelines, which will have destinations at our facilities in Chambers County, Texas.  This system consists of the 901-mile Chaparral Pipeline and the 179-mile Quanah Pipeline. Intrastate transportation services provided on 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 that transport 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 facilities, NGL fractionators and other assets located in Louisiana.

•

The Seminole NGL Pipeline transports NGLs from the Hobbs hub and the Permian Basin to markets in southeast Texas, including our Chambers County NGL fractionation complex.  NGLs originating on the Mid-America Pipeline System are a significant source of throughput for the Seminole NGL Pipeline.

•

The Shin Oak NGL Pipeline transports NGL production from Orla, Texas in the Permian Basin to our Chambers County NGL fractionation and storage complex.

•

The Texas Express Pipeline extends from Skellytown, Texas to our Chambers County NGL fractionation and storage complex.  Mixed NGLs from production fields located in 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.  In addition, the Texas Express Pipeline transports mixed NGLs gathered by the Texas Express Gathering System.  Also, mixed NGLs originating from the Denver-Julesburg (“DJ”) Basin in Colorado are transported to the Texas Express Pipeline using the Front Range Pipeline.

•

The Skelly-Belvieu Pipeline transports mixed NGLs from Skellytown, Texas to Chambers County, Texas.  The Skelly-Belvieu Pipeline receives a significant quantity of NGLs through an interconnect with our Mid-America Pipeline System at Skellytown.

•

The Front Range Pipeline transports mixed NGLs from natural gas processing facilities located in the DJ Basin in Colorado to an interconnect with our Texas Express Pipeline, Mid-America Pipeline System and other third-party facilities located at Skellytown, Texas.

•

The Houston Ship Channel Pipeline System connects our Chambers County, Texas assets to our marine terminals on the Houston Ship Channel and to area petrochemical plants, refineries and other pipelines.

•

The Panola Pipeline transports mixed NGLs from injection points near Carthage, Texas to Chambers County, Texas and supports the Haynesville and Cotton Valley crude oil and natural gas production areas.

•

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 Aegis Ethane Pipeline (“Aegis”) delivers purity ethane to petrochemical facilities located along the southeast Texas and Louisiana Gulf Coast.  Aegis, when combined with our Enterprise Ethane Pipeline and a portion of our South Texas NGL Pipeline System, forms an ethane header system stretching from Corpus Christi, Texas to the Mississippi River in Louisiana.

•

The Lou-Tex NGL Pipeline transports mixed NGLs, purity NGL products and refinery grade propylene (“RGP”) between the Louisiana and Texas markets.

			Net Plant	Total Plant
		Ownership	Capacity	Capacity
Description of Asset	Location	Interest	(MBPD) (1)	(MBPD) (2)
NGL fractionation facilities:
Chambers County:
Fracs 1, 2 and 3	Texas	75.0% (3)	189	245
Fracs 4, 5, 6, 9, 10, 11 and 12	Texas	100.0%	770	770
Fracs 7 and 8	Texas	75.0% (4)	128	170
Total Chambers County			1,087	1,185
Shoup and Armstrong	Texas	100.0%	97	97
Hobbs	Texas	100.0%	75	75
Norco	Louisiana	100.0%	75	75
Promix	Louisiana	50.0% (5)	73	145
Tebone	Louisiana	100.0%	30	30
Baton Rouge	Louisiana	32.2% (6)	19	60
Total			1,456	1,667

(1)	The approximate net plant capacity does not necessarily correspond to our ownership interest in each facility.  The capacity 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)	Total plant capacity reflects nameplate capacity at our fractionation facilities.  Actual fractionation capacity, which may routinely exceed nameplate capacity, can vary based on operating conditions including the composition of the NGLs being processed.
(3)	We proportionately consolidate a 75% undivided interest in these fractionators.
(4)	We own a 75% consolidated equity interest in NGL fractionators 7 and 8 through our majority owned subsidiary, Enterprise EF78 LLC.  On February 16, 2024, we acquired the remaining 25% equity interest in Enterprise EF78 LLC.  For more information, see Note 20 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report.
(5)	Our 50% ownership interest in the Promix NGL fractionator is held indirectly through our equity method investment in K/D/S Promix, L.L.C.
(6)	Our 32.2% ownership interest in the Baton Rouge fractionator is held indirectly through our equity method investment in Baton Rouge Fractionators LLC.

•

We own and operate NGL fractionators located in Chambers County, Texas.  These fractionators process mixed NGLs from several major NGL supply basins in North America, including the Permian Basin, Rocky Mountains, Eagle Ford Shale, Mid-Continent and San Juan Basin.  Our Chambers County NGL fractionators are connected to our network of NGL supply and distribution pipelines, approximately 170 MMBbls of underground salt dome storage capacity, along with access to international markets through our marine terminals located on the Houston Ship Channel.

•

The Shoup and Armstrong NGL fractionators in South Texas process mixed NGLs supplied by regional natural gas processing facilities.  Purity NGL products from these fractionators are transported to local markets in the Corpus Christi area and also to Chambers County, Texas using our South Texas NGL Pipeline System.

•

The Hobbs NGL fractionator serves NGL producers in West Texas, New Mexico, Colorado and Wyoming. This 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 NGL Pipeline, thus providing customers access to the Conway hub and Chambers County, Texas.

•

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

			Net Usable
			Storage
		Ownership	Capacity
Description of Asset	Location	Interest	(MMBbls) (1)
Chambers County storage complex	Texas	100.0%	169.5
Almeda and Markham (2)	Texas	Leased	12.4
Breaux Bridge, Anse La Butte and Sorrento (3)	Louisiana	100.0%	11.0
Petal (4)	Mississippi	100.0%	5.4
Hutchinson (5)	Kansas	100.0%	4.0
Others (6)	Various	Various	14.4
Total			216.7

(1)	Net usable storage capacity is based on our ownership interest or contractual right-of-use.
(2)	These storage facilities are used in connection with our South Texas NGL Pipeline System.
(3)	These storage facilities are used in connection with our Louisiana Pipeline System.
(4)	This storage facility is used in connection with our Dixie Pipeline.
(5)	This storage facility is used in connection with our Mid-America Pipeline System.
(6)	Primarily consists of operational storage capacity for our major pipeline systems, including the Mid-America Pipeline System, Dixie Pipeline and TE Products Pipeline.  We own substantially all of this storage capacity.

•

The Enterprise Hydrocarbons Terminal (“EHT”) provides terminaling services to exporters, marketers, distributors, chemical companies and major integrated oil companies.  EHT has extensive waterfront access consisting of eight deep-water ship docks and a barge dock.  The terminal 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 enables us to handle larger vessels than our competitors because our waterfront has fewer draft and beam (width) restrictions.  The size and structure of our waterfront allows us to receive and unload products for our customers and provide terminaling services.

•

The Morgan’s Point Ethane Export Terminal , located on the Houston Ship Channel, has a nameplate loading capacity of approximately 10,000 barrels per hour of fully refrigerated ethane and is the largest of its kind in the world. The terminal supports domestic production of U.S. ethane from shale plays by providing the global petrochemical industry with access to a low-cost feedstock option and opportunities for supply diversification.  Ethane volumes handled by the terminal are sourced from our Chambers County NGL fractionation and storage complex.  Ethane loading volumes at the terminal averaged 198 MBPD, 168 MBPD and 157 MBPD during the years ended December 31, 2023, 2022 and 2021, respectively.

			Operational
			Storage	Pipeline
		Ownership	Capacity	Length
Description of Asset	Location(s)	Interest	(MMBbls) (2)	(Miles)
Seaway Pipeline (1)	Texas, Oklahoma	50.0% (3)	9.7	1,273
West Texas System (1)	Texas, New Mexico	100.0%	1.7	1,081
Midland-to-ECHO System	Texas	Various (4)	3.7	938
Basin Pipeline (1)	Texas, New Mexico, Oklahoma	13.0% (5)	5.2	601
South Texas Crude Oil Pipeline System	Texas	100.0%	5.6	508
EFS Midstream System	Texas	100.0%	0.3	500
Eagle Ford Crude Oil Pipeline System	Texas	50.0% (6)	4.5	390
Total			30.7	5,291

(1)	Transportation services provided on these liquids pipelines are regulated, in whole or part, by federal governmental agencies.
(2)	Operational storage capacity amounts presented on a gross basis.
(3)	Our 50% ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Holdings LLC (“Seaway”).
(4)	We own an 80% consolidated interest in the 417-mile Midland-to-Sealy section of the Midland-to-ECHO 1 Pipeline through our majority owned subsidiary, Whitethorn Pipeline Company LLC.  On February 16, 2024, we acquired the remaining 20% equity interest in Whitethorn Pipeline Company LLC.  For more information, see Note 20 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report.  Additionally, we proportionately consolidate our 29% undivided interest in the 521-mile Midland-to-Webster pipeline, which we refer to as the Midland-to-ECHO 3 Pipeline.
(5)	We proportionately consolidate our 13% undivided interest in the Basin Pipeline.
(6)	Our 50% ownership interest in the Eagle Ford Crude Oil Pipeline System is held indirectly through our equity method investment in Eagle Ford Pipeline LLC.

•

The Midland- to-ECHO System supports Permian Basin crude oil production by providing producers and other shippers with transportation solutions that are both cost-efficient and operationally flexible.  After aggregating crude at our Midland terminal, the system has the capability to transport multiple grades of crude oil, including West Texas Intermediate (“WTI”), WTI light sweet crude oil (“West Texas Light”), West Texas Sour, and condensate, to our Enterprise Crude Houston (“ECHO”) storage terminal (using batched shipments to safeguard crude quality) for further delivery to markets along the Gulf Coast.  Using the ECHO terminal, shippers on the Midland-to-ECHO System have access to every refinery in Houston, Texas City, Beaumont and Port Arthur, Texas, as well as our crude oil export terminal facilities.

•

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 an industry trading hub and price settlement point for WTI crude oil on the New York Mercantile Exchange (“NYMEX”).

•

The West Texas System connects crude oil gathering systems in West Texas and southeast New Mexico to our terminal facility located in Midland, Texas.  The West Texas System, including the Loving County pipeline, is a key part of our strategic crude oil aggregation program designed to support Permian Basin producers with a transport capacity over 600 MBPD.  At Midland, shippers have access to storage and terminal services, as well as connectivity to multiple transportation alternatives such as trucking and pipeline infrastructure that offer access to various downstream markets, including the Gulf Coast.

•

The Basin Pipeline transports crude oil from the Permian Basin in West Texas and southern New Mexico to the Cushing hub.

•

The EFS Midstream System serves producers in the Eagle Ford Shale by providing condensate gathering and processing services as well as gathering, treating and compression services for associated natural gas.  The EFS Midstream System includes 500 miles of gathering pipelines, 11 central gathering plants having a combined condensate storage capacity of 0.3 MMBbls, 201 MBPD of condensate stabilization capacity and 1.0 Bcf/d of associated natural gas treating capacity.

•

The South Texas Crude Oil Pipeline System has the capacity to transport approximately 450 MBPD of crude oil and condensate originating in South Texas to customers in the Houston area.  This system includes storage terminal assets located at Lyssy, Milton, Marshall and Sealy, Texas.  The South Texas Crude Oil Pipeline System also includes our Rancho II pipeline, which extends 89-miles from the Sealy terminal to our ECHO terminal.  From ECHO, we have connectivity to refinery customers and our marine terminals along the Texas Gulf Coast.

•

The Eagle Ford Crude Oil Pipeline System transports crude oil and condensate for producers in South Texas.  The system, which is effectively looped and has a capacity to transport over 600 MBPD of light and medium grades of crude oil, consists of 390 miles of crude oil and condensate pipelines originating in Gardendale, Texas and extending to Corpus Christi, Texas.  The system interconnects with our South Texas Crude Oil Pipeline System in Wilson County, Texas and our Corpus Christi marine terminal.

			Number of	Net Storage
		Ownership	Above-Ground	Capacity
Description of Asset	Location	Interest	Tanks in Service	(MMBbls)
EHT (crude oil)	Texas	100.0%	81	24.0
ECHO (1)	Texas	100.0%	15	6.6
Midland (2)	Texas	100.0%	13	5.2
Beaumont Marine West	Texas	100.0%	12	4.2
Cushing	Oklahoma	100.0%	19	3.5
Corpus Christi	Texas	50.0% (3)	4	0.7
Total			144	44.2

(1)	Number of tanks and storage capacity excludes three tanks that are used in the operation of our Midland-to-ECHO 1 pipeline and three tanks owned by Seaway.
(2)	Number of tanks and storage capacity excludes three tanks that are used in the operation of our Midland-to-ECHO 1 pipeline.
(3)	Our 50% ownership interest in the terminal is held indirectly through our equity method investment in Eagle Ford Terminals Corpus Christi LLC.

•

The EHT marine terminal located on the Houston Ship Channel includes export assets capable of loading up to 2.9 MMBPD, or 88 MMBbls per month, of crude oil.  The crude oil terminal at EHT represents one of the largest such facilities on the Gulf Coast.  As noted previously, EHT 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.

•

The ECHO terminal is located in Houston, Texas and provides storage customers with access to major refineries located in the Houston, Texas City and Beaumont/Port Arthur areas.  Beginning in March 2022, the ECHO terminal became one of two physical delivery points for the Midland WTI American Gulf Coast futures contract (“HOU”) traded on the Intercontinental Exchange (“ICE”).  ECHO also has connections to marine terminals, including EHT, that provide access to any refinery on the U.S. Gulf Coast and international markets.

•

The Beaumont Marine West terminal is located on the Neches River near Beaumont, Texas.  This terminal includes three deep-water docks and one barge dock that facilitate the exporting and importing of crude oil and related products.

•

The Cushing terminal is located at the Cushing hub in Oklahoma and provides crude oil storage, pumpover and trade documentation services.  This terminal is one of the origination points for our Seaway Pipeline.

•

The Midland terminal provides crude oil storage, pumpover and trade documentation services.  The Midland terminal is the origination point for our Midland-to-ECHO pipelines.

•

The Corpus Christi terminal, located in Corpus Christi, Texas, is capable of loading ocean-going vessels with either crude oil or condensate.  The terminal includes one deep-water ship dock and serves Eagle Ford Shale and Permian Basin producers through a connection with our Eagle Ford Crude Oil Pipeline System.

				Net Capacity (1)
			Pipeline	Pipeline	Natural Gas	Usable
		Ownership	Length	Capacity	Treating	Storage
Description of Asset	Location(s)	Interest	(Miles)	(MMcf/d)	(MMcf/d)	(Bcf)
Texas Intrastate System (2)	Texas	Various (5)	6,719	7,328	–	12.9
Acadian Gas System (2)	Louisiana	100.0% (6)	1,409	4,825	–	1.2
Jonah Gathering System	Wyoming	100.0%	786	2,360	–	–
Delaware Basin Gathering System	Texas, New Mexico	100.0%	1,772	2,300	–	–
Midland Basin Gathering System	Texas	100.0%	1,818	1,900	–	–
Piceance Basin Gathering System	Colorado	100.0%	195	1,800	–	–
White River Hub (3)	Colorado	50.0% (7)	10	1,500	–	–
BTA Gathering System (4)	Texas	100.0% (8)	804	1,420	240	–
Haynesville Gathering System	Louisiana, Texas	100.0%	364	1,300	810	–
San Juan Gathering System	New Mexico, Colorado	100.0%	5,568	1,200	–	–
Indian Springs Gathering System (4)	Texas	80.0% (9)	145	160	–	–
Delmita Gathering System	Texas	100.0%	201	145	–	–
South Texas Gathering System	Texas	100.0%	524	143	320	–
Old Ocean Pipeline	Texas	50.0% (10)	240	80	–	–
Big Thicket Gathering System (4)	Texas	100.0%	234	60	–	–
Central Treating Facility	Colorado	100.0%	–	–	200	–
Total			20,789	26,521	1,570	14.1

(1)	Net capacity amounts are based on our ownership interest or contractual right-of-use.
(2)	Transportation services provided on these pipeline systems, in whole or part, are regulated by both federal and state governmental agencies.
(3)	Services provided by the White River Hub are regulated by federal governmental agencies.
(4)	Transportation services provided on these systems are regulated in part by state governmental agencies.
(5)	We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,469 miles of the Texas Intrastate System.  The Texas Intrastate System also includes our Wilson natural gas storage facility, which consists of a network of owned underground salt dome storage caverns located in Wharton County, Texas with an aggregate 12.9 Bcf of usable storage capacity.
(6)	The Acadian Gas System includes a leased 1.2 Bcf underground salt dome natural gas storage cavern located at Napoleonville, Louisiana.
(7)	Our 50% ownership interest in White River Hub is held indirectly through our equity method investment in White River Hub, LLC.
(8)	This system includes approximately 56 miles of leased pipelines.
(9)	We proportionately consolidate our 80% undivided interest in the Indian Springs Gathering System.
(10)	Our 50% ownership interest in the Old Ocean Pipeline is held indirectly through our equity method investment in Old Ocean Pipeline, LLC.

•

The Texas Intrastate System is comprised of the 6,071-mile Enterprise Texas pipeline system and the 648-mile Channel pipeline system. The Texas Intrastate System gathers, transports and stores natural gas from supply basins in Texas including the Permian Basin and Eagle Ford and Barnett Shales for delivery to local gas distribution companies, electric utility plants and industrial and municipal consumers. The system is also connected to regional natural gas processing facilities and other intrastate and interstate pipelines.  The Texas Intrastate System serves a number of commercial markets in Texas, including Corpus Christi, San Antonio/Austin, Beaumont/Orange and Houston, 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 1,006-mile Acadian pipeline, 292-mile Acadian Haynesville Extension pipeline, 83-mile Gillis Lateral pipeline and 28-mile Enterprise Pelican pipeline.  The Acadian Gas System links natural gas supplies from Louisiana (e.g., from the Haynesville Shale supply basin) and offshore Gulf of Mexico developments with local gas distribution companies, electric utility plants and industrial customers located primarily in the Baton Rouge/New Orleans/Mississippi River corridor.  Additionally, the Acadian Gas System delivers natural gas production from the Haynesville Shale to the liquefied natural gas (“LNG”) markets in South Louisiana via the Gillis Lateral pipeline.

•

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 facilities, including our Pioneer facility.

•

The Piceance Basin Gathering System gathers natural gas produced from the Piceance Basin in northwestern Colorado to our Meeker natural gas processing facility.

•

The Midland Basin Gathering System , which is located in West Texas, gathers natural gas from the Midland Basin for delivery to our Midland Basin processing facility.  We acquired this system in February 2022, along with our Midland Basin processing facility.  For more information regarding this acquisition, see Note 12 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report.

•

The Delaware Basin Gathering System is comprised of the 1,130-mile Carlsbad pipeline system, the 585-mile Waha pipeline system, the 34-mile Orla pipeline system and the 23-mile Mentone pipeline system. The Delaware Basin Gathering System gathers natural gas from the Delaware Basin for delivery to regional natural gas processing facilities, including our Delaware Basin natural gas processing facility, and delivers residue and treated natural gas into our Texas Intrastate System and third-party pipelines.

•

The White River Hub is a natural gas hub facility serving producers in the Piceance Basin.  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 BTA Gathering System , which is located in East Texas, gathers and treats natural gas from the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations.  This system includes our Fairplay Gathering System.

•

The Haynesville Gathering System gathers and treats 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 Acadian Haynesville Extension pipeline) markets served by our Acadian Gas System.

•

The San Juan Gathering System gathers and treats natural gas produced from the San Juan Basin in northern New Mexico and southern Colorado and delivers the natural gas either directly into interstate pipelines or to regional natural gas plants, including our Chaco facility, for processing prior to being transported on interstate pipelines.

•

The Indian Springs Gathering System , along with the Big Thicket Gathering System , gather natural gas from the Woodbine, Wilcox and Yegua production areas in East Texas.

•

The Delmita Gathering System gathers natural gas from the Frio-Vicksburg formation in South Texas for delivery to our South Texas natural gas processing facilities.

•

The South Texas Gathering System gathers natural gas from the Olmos and Wilcox formations for delivery to our South Texas natural gas processing facilities.

•

The Old Ocean Pipeline transports natural gas from an injection point on our Texas Intrastate System near Maypearl, Texas for delivery to a pipeline interconnect at Sweeny, Texas.  A third party serves as operator of the pipeline, which has a gross natural gas transportation capacity of 160 MMcf/d.

•

The Central Treating Facility is located in Rio Blanco County, Colorado and serves producers in the Piceance Basin.  Natural gas delivered to the treating facility is treated to remove impurities and transported to our Meeker processing trains for further processing.

•

propylene production facilities, which include propylene fractionation units and PDH facilities, and related pipelines and marketing activities;

•

butane isomerization complex and related DIB operations;

•

octane enhancement, iBDH and HPIB production facilities;

•

refined products pipelines, terminals and related marketing activities;

•

an ethylene export terminal and related operations; and

•

marine transportation business.

			Net Plant	Total Plant
		Ownership	Capacity	Capacity
Description of Asset	Location	Interest	(MBPD)	(MBPD)
Propylene fractionation facilities:
Chambers County (six units)	Texas	Various  (1)	82	95
BRPC (one unit)	Louisiana	30.0%  (2)	7	23
Total			89	118
PDH facilities:
PDH 1	Texas	100.0%	25	25
PDH 2	Texas	100.0%	25	25
Total			50	50

(1)	We proportionately consolidate a 66.7% undivided interest in three of the propylene splitters, which have an aggregate 40 MBPD of total plant capacity.  The remaining three propylene fractionation units are wholly owned.
(2)	Our 30% ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC (“BRPC”).

		Ownership	Length
Description of Asset	Location(s)	Interest	(Miles)
Texas RGP Gathering System	Texas	100.0%	708
Lou-Tex Propylene Pipeline	Texas, Louisiana	100.0%	267
North Dean Pipeline System	Texas	100.0%	254
Propylene Splitter PGP Distribution System	Texas	100.0%	152
Taurus Pipeline	Texas	70.0%  (1)	115
Louisiana RGP Gathering System	Louisiana	100.0%	63
Lake Charles PGP Pipeline	Texas, Louisiana	50.0%  (2)	27
Sabine Pipeline	Texas, Louisiana	100.0%	24
La Porte PGP Pipeline	Texas	80.0%  (3)	20
Total			1,630

(1)	We own a 70% consolidated interest in the Taurus Pipeline through our majority owned subsidiary Steor LLC.
(2)	We proportionately consolidate our 50% undivided interest in the Lake Charles PGP Pipeline.
(3)	We own an 80% consolidated interest in the La Porte PGP Pipeline through our majority owned subsidiaries, La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C.

		For the Year Ended December 31,
		2023				2022				2021
Refined products transportation (MBPD)			502				447				464
Petrochemical transportation (MBPD)			–				–				170
NGL transportation (MBPD)			51				56				52

•

Our operations along the Gulf Coast, including those at our Chambers County complex, may be affected by weather events such as hurricanes and tropical storms, which generally arise during the summer and fall months.

•

Residential demand for natural gas typically peaks during the winter months in connection with heating needs and during the summer months for power generation for air conditioning. These seasonal trends affect throughput volumes on our natural gas pipelines and associated natural gas storage levels and marketing results.

•

Residential demand for propane typically peaks during the winter months in connection with heating needs in rural areas. These seasonal trends can affect throughput volumes on our TE Products Pipeline, Dixie Pipeline and Mid-America Pipeline System and associated terminals.

•

Due to increased demand for fuel additives used in the production of motor gasoline, our isomerization and octane enhancement businesses experience higher levels of demand during the summer driving season, which typically occurs in the spring and summer months.  Likewise, shipments of refined products and normal butane experience similar changes in demand due to their use in motor fuels.

•

Extreme temperatures and ice during the winter months can negatively impact our gas processing assets as they may experience freeze offs.  In addition, these conditions can negatively affect our trucking and inland marine operations on the upper Mississippi and Illinois rivers.

•

The impact of a global public health crisis or foreign conflict on global oil and gas markets may have material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties.

•

Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.

•

Changes in demand for and prices and production of hydrocarbon products 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.

•

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

•

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

•

Several of our assets have been in service for many years and require significant expenditures to maintain them.  As a result, an increase in future maintenance or repair costs or delays in completing necessary maintenance or repair activities could have a material adverse effect on our financial position, results of operations and cash flows.

•

The inability to continue to access lands owned by third parties and governmental bodies could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows.

•

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.

•

A natural disaster, catastrophe, terrorist attack or other extraordinary 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.

•

A cyber-attack on our information technology (“IT”) or operational technology (“OT”) systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows.

•

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

•

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

•

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

•

Federal, state or local regulatory measures (including those related to climate, environmental, health, safety and pipeline integrity matters) 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.

•

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

•

Changes in management’s estimates and assumptions may have a material impact on our financial statements and financial performance.

•

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.

•

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.

•

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.

•

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

•

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

•

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

•

Unitholders may have a liability to repay distributions.

•

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 tax treatment depends on our status as a partnership for federal income tax purposes, which could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

•

A successful IRS contest of the federal income tax positions we take and certain valuation methodologies we adopt in determining a unitholder’s allocation of income, gain, loss and deductions 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.

•

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we would pay the taxes directly to the IRS and our cash available for distribution to our unitholders might be substantially reduced.

•

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

•

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

•

We 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.

•

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.

•

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 for capital investments;

•

credit rating agencies may take a negative view of the energy sector or 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 investments, 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.

•

we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel, the unavailability of or delays in obtaining necessary materials as a result of supply chain disruptions (including those caused by public health emergency restrictions or geopolitical events, such as the Russian invasion of Ukraine or ongoing conflicts in the Middle East), 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 crude oil or 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 or construction of a new petrochemical facility) 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.

•

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.

•

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;

•

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.

While we currently believe that our classification as a partnership for federal income tax purposes continues to provide  a net benefit for our unitholders, should we continue to see (i) additional publicly traded partnerships elect to be taxed as corporations, which could result in a further decrease in the total market capitalization of the publicly traded partnership sector, (ii) lower demand for equity capital in the publicly traded partnership sector, (iii) the absence of a historic premium in the market valuation of publicly traded partnerships compared to midstream energy companies taxed as corporations  (or if we see any discount in the valuation of our partnership compared to such companies), or (iv) a combination thereof that results in a material difference in our cost of capital or limits our access to capital, the board of directors of our general partner may determine it is in our unitholders’ best interest to change our classification as a partnership for federal income tax purposes. Should the general partner recommend that we change our tax classification, such change would be subject to the approval of our common unitholders.

Period		Total Number of Units Purchased				Average Price Paid per Unit				Total Number Of Units Purchased as Part of 2019 Buyback Program				Remaining Dollar Amount of Units That May Be Purchased Under the 2019 Buyback Program ($ thousands)
2019 Buyback Program: (1)
October 2023			–			$	–				–			$	1,177,244
November 2023			2,867,527			$	26.14				2,867,527			$	1,102,297
December 2023			784,303			$	26.28				784,303			$	1,081,686
Vesting of phantom unit awards:
November 2023 (2)			6,197			$	25.98				n/a				n/a

(1)	In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of EPD’s common units.  Units repurchased under this program are cancelled immediately upon acquisition.
(2)	Of the 24,262 phantom unit awards that vested in November 2023 and converted to common units, 6,197 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program.  We cancelled these units immediately upon acquisition.

/d	=	per day	MMBPD	=	million barrels per day
BBtus	=	billion British thermal units	MMBtus	=	million British thermal units
Bcf	=	billion cubic feet	MMcf	=	million cubic feet
BPD	=	barrels per day	MWac	=	megawatts, alternating current
MBPD	=	thousand barrels per day	MWdc	=	megawatts, direct current
MMBbls	=	million barrels	TBtus	=	trillion British thermal units

•

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

•

NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane);

•

crude oil gathering, transportation, storage, and marine terminals;

•

propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;

•

petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and

•

a marine transportation business that operates on key U.S. inland and intracoastal waterway systems.

•

the Bahia NGL Pipeline (first half of 2025);

•

a natural gas processing train at our Mentone West location in the Delaware Basin (second half of 2025);

•

an eighth natural gas processing train (“Orion”) in the Midland Basin (second half of 2025); and

•

an NGL fractionator (“Frac 14”) and an associated deisobutanizer (“DIB”) unit in Chambers County, TX (second half of 2025)

In July 2023, we placed into service our sixth Midland Basin natural gas processing train (“Poseidon”), which is located in Glasscock County, Texas.  Poseidon has a nameplate capacity of 300 MMcf/d and can extract more than 40 MBPD of NGLs.  Supported by long-term acreage dedication agreements, Poseidon will support Permian Basin producers as they meet growing demand in the U.S. and internationally.

							Polymer	Refinery	Indicative Gas
	Natural			Normal		Natural	Grade	Grade	Processing
	Gas,	Ethane,	Propane,	Butane,	Isobutane,	Gasoline,	Propylene,	Propylene,	Gross Spread
	$/MMBtu	$/gallon	$/gallon	$/gallon	$/gallon	$/gallon	$/pound	$/pound	$/gallon
	(1)	(2)	(2)	(2)	(2)	(2)	(3)	(3)	(4)
2022 by quarter:
1st Quarter	$4.96	$0.40	$1.30	$1.59	$1.60	$2.21	$0.63	$0.39	$0.55
2nd Quarter	$7.17	$0.59	$1.24	$1.50	$1.68	$2.17	$0.61	$0.40	$0.46
3rd Quarter	$8.20	$0.55	$1.08	$1.19	$1.44	$1.72	$0.47	$0.28	$0.26
4th Quarter	$6.26	$0.39	$0.79	$0.97	$1.03	$1.54	$0.32	$0.18	$0.17
2022 Averages	$6.65	$0.48	$1.10	$1.31	$1.44	$1.91	$0.51	$0.31	$0.36
2023 by quarter:
1st Quarter	$3.44	$0.25	$0.82	$1.11	$1.16	$1.62	$0.50	$0.22	$0.37
2nd Quarter	$2.09	$0.21	$0.67	$0.78	$0.84	$1.44	$0.40	$0.21	$0.37
3rd Quarter	$2.54	$0.30	$0.68	$0.83	$0.94	$1.55	$0.36	$0.15	$0.40
4th Quarter	$2.88	$0.23	$0.67	$0.91	$1.07	$1.48	$0.46	$0.17	$0.33
2023 Averages	$2.74	$0.25	$0.71	$0.91	$1.00	$1.52	$0.43	$0.19	$0.37

(1)	Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts , which is a division of S&P Global, Inc.
(2)	NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu, Texas Non-TET commercial index prices as reported by Oil Price Information Service, which is a division of Dow Jones .
(3)	Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Markit (“IHS”), which is a division of S&P Global, Inc.  Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS.
(4)	The “Indicative Gas Processing Gross Spread” represents our generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions.  Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs in Chambers County, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana. Our estimate of the indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market.   In addition, the actual gas processing spread earned at each plant is further influenced by regional pricing and extraction dynamics.

	WTI	Midland	Houston	LLS
	Crude Oil,	Crude Oil,	Crude Oil	Crude Oil,
	$/barrel	$/barrel	$/barrel	$/barrel
	(1)	(2)	(2)	(3)
2022 by quarter:
1st Quarter	$94.29	$96.43	$96.77	$96.77
2nd Quarter	$108.41	$109.66	$109.96	$110.17
3rd Quarter	$91.56	$93.41	$93.77	$94.17
4th Quarter	$82.64	$83.97	$84.33	$85.50
2022 Averages	$94.23	$95.87	$96.21	$96.65
2023 by quarter:
1st Quarter	$76.13	$77.50	$77.74	$79.00
2nd Quarter	$73.78	$74.48	$74.68	$75.87
3rd Quarter	$82.26	$83.85	$84.02	$84.72
4th Quarter	$78.32	$79.62	$79.89	$80.93
2023 Averages	$77.62	$78.86	$79.08	$80.13

(1)	WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.
(2)	Midland and Houston crude oil prices are based on commercial index prices as reported by Argus.
(3)	Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts.

		For the Year Ended December 31,
		2023				2022
Revenues		$	49,715			$	58,186
Costs and expenses:
Operating costs and expenses:
Cost of sales			37,023				45,836
Other operating costs and expenses			3,695				3,454
Depreciation, amortization and accretion expenses			2,279				2,158
Asset impairment charges			30				53
Net losses (gains) attributable to asset sales and related matters			(10	)			1
Total operating costs and expenses			43,017				51,502
General and administrative costs			231				241
Total costs and expenses			43,248				51,743
Equity in income of unconsolidated affiliates			462				464
Operating income			6,929				6,907
Other income (expense):
Interest expense			(1,269	)			(1,244	)
Other, net			41				34
Total other expense, net			(1,228	)			(1,210	)
Income before income taxes			5,701				5,697
Provision for income taxes			(44	)			(82	)
Net income			5,657				5,615
Net income attributable to noncontrolling interests			(125	)			(125	)
Net income attributable to preferred units			(3	)			(3	)
Net income attributable to common unitholders		$	5,529			$	5,487

		For the Year Ended December 31,
		2023				2022
NGL Pipelines & Services:
Sales of NGLs and related products		$	14,846			$	21,307
Midstream services			2,799				2,952
Total			17,645				24,259
Crude Oil Pipelines & Services:
Sales of crude oil			18,185				17,301
Midstream services			1,151				1,260
Total			19,336				18,561
Natural Gas Pipelines & Services:
Sales of natural gas			2,373				5,019
Midstream services			1,403				1,241
Total			3,776				6,260
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products			7,689				8,003
Midstream services			1,269				1,103
Total			8,958				9,106
Total consolidated revenues		$	49,715			$	58,186

		For the Year Ended December 31,
		2023				2022
Interest charged on debt principal outstanding (1)		$	1,355			$	1,288
Impact of interest rate hedging program, including related amortization			(5	)			19
Interest costs capitalized in connection with construction projects (2)			(106	)			(90	)
Other			25				27
Total		$	1,269			$	1,244

(1)

The weighted-average interest rates on debt principal outstanding were 4.56% and 4.33% during the years ended December 31, 2023 and 2022, respectively.

(2)

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) on a straight-line basis 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 based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.

•	Our NGL Pipelines & Services business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals.

•	Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities.

•	Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas.  This segment also includes our natural gas marketing activities.

•

Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and PDH facilities, and related pipelines and marketing activities, (ii) butane isomerization complex and related DIB operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) an ethylene export terminal and related operations; and (vi) marine transportation business.

		For the Year Ended December 31,
		2023				2022
Gross operating margin by segment:
NGL Pipelines & Services		$	4,898			$	5,142
Crude Oil Pipelines & Services			1,707				1,655
Natural Gas Pipelines & Services			1,077				1,042
Petrochemical & Refined Products Services			1,694				1,517
Total segment gross operating margin (1)			9,376				9,356
Net adjustment for shipper make-up rights			19				(47	)
Total gross operating margin (non-GAAP)		$	9,395			$	9,309

(1)

Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

		For the Year Ended December 31,
		2023				2022
Operating income		$	6,929			$	6,907
Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses (1)			2,215				2,107
Asset impairment charges in operating costs and expenses			30				53
Net losses (gains) attributable to asset sales and related matters in operating costs and expenses			(10	)			1
General and administrative costs			231				241
Total gross operating margin (non-GAAP)		$	9,395			$	9,309

(1)	Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin.

		For the Year Ended December 31,
		2023				2022
Segment gross operating margin:
Natural gas processing and related NGL marketing activities		$	1,300			$	1,946
NGL pipelines, storage and terminals			2,771				2,362
NGL fractionation			827				834
Total		$	4,898			$	5,142
Selected volumetric data:
NGL pipeline transportation volumes (MBPD)			4,040				3,703
NGL marine terminal volumes (MBPD)			821				723
NGL fractionation volumes (MBPD)			1,556				1,339
Equity NGL-equivalent production volumes (MBPD) (1)			175				182
Fee-based natural gas processing volumes (MMcf/d) (2, 3)			5,848				5,182

(1)	Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities.  The total equity NGL-equivalent production volumes also include residue natural gas volumes from our natural gas processing business.
(2)	Volumes reported correspond to the revenue streams earned by our natural gas processing plants.
(3)	Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d.

		For the Year Ended December 31,
		2023				2022
Segment gross operating margin:
Midland-to-ECHO System and related business activities		$	551			$	393
Other crude oil pipelines, terminals and related marketing results			1,156				1,262
Total		$	1,707			$	1,655
Selected volumetric data:
Crude oil pipeline transportation volumes (MBPD)			2,461				2,222
Crude oil marine terminal volumes (MBPD)			913				788

		For the Year Ended December 31,
		2023				2022
Segment gross operating margin		$	1,077			$	1,042
Selected volumetric data:
Natural gas pipeline transportation volumes (BBtus/d)			18,365				17,107

		For the Year Ended December 31,
		2023				2022
Segment gross operating margin:
Propylene production and related activities		$	583			$	564
Butane isomerization and related operations			124				114
Octane enhancement and related plant operations			442				394
Refined products pipelines and related activities			357				277
Ethylene exports and related activities			123				123
Marine transportation and other services			65				45
Total		$	1,694			$	1,517
Selected volumetric data:
Propylene production volumes (MBPD)			101				101
Butane isomerization volumes (MBPD)			112				108
Standalone DIB processing volumes (MBPD)			176				159
Octane enhancement and related plant sales volumes (MBPD) (1)			36				39
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)			836				747
Marine terminal volumes, primarily refined products and petrochemicals (MBPD)			320				202

(1)	Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Chambers County complex and our HPIB facility located adjacent to the Houston Ship Channel.

		For the Year Ended December 31,
		2023				2022
Net cash flows provided by operating activities		$	7,569			$	8,039
Cash used in investing activities			3,197				4,954
Cash used in financing activities			4,258				5,844

•

a $501 million year-to-year decrease from changes in operating accounts primarily due to the use of working capital employed in our marketing activities, which includes the impact of (i) fluctuations in commodity prices, (ii) timing of our inventory purchase and sale strategies, and (iii) changes in margin deposit requirements associated with our commodity derivative instruments; partially offset by

•

a $31 million year-to-year increase resulting from higher partnership earnings (determined by adjusting our $42 million year-to-year increase in net income for changes in the non-cash items identified on our Statements of Consolidated Cash Flows).

•

a net $ 3.2 billion cash outflow in February 2022 in connection with the acquisition of our Midland Basin System; partially offset by

•

a $1.3 billion year-to-year increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part II, Item 7 for additional information).

•

a net cash inflow of $456 million related to debt transactions that occurred during the year ended December 31, 2023 compared to a net cash outflow of $1.3 billion related to debt transactions that occurred during the year ended December 31, 2022.  In 2023, we issued $1.75 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.25 billion principal amount of senior notes and net repayments of $45 million under EPO’s commercial paper program.  In 2022 we repaid $1.75 billion aggregate principal amount of senior and junior subordinated notes, partially offset by net issuances of $495 million under EPO’s commercial paper program; partially offset by

•

a $206 million year-to-year increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit.

		For the Year Ended December 31,
		2023				2022
Net income attributable to common unitholders (GAAP) (1)		$	5,529			$	5,487
Adjustments to net income attributable to common unitholders to derive DCF and Operational DCF (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expenses			2,343				2,245
Cash distributions received from unconsolidated affiliates (2)			488				544
Equity in income of unconsolidated affiliates			(462	)			(464	)
Asset impairment charges			32				53
Change in fair market value of derivative instruments			33				78
Deferred income tax expense			12				60
Sustaining capital expenditures (3)			(413	)			(372	)
Other, net			(24	)			(2	)
Operational DCF (non-GAAP)		$	7,538			$	7,629
Proceeds from asset sales and other matters			42				122
Monetization of interest rate derivative instruments accounted for as cash flow hedges			21				–
DCF (non-GAAP)		$	7,601			$	7,751
Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards		$	4,393			$	4,182
Cash distribution per common unit declared by Enterprise GP with respect to period (4)		$	2.0050			$	1.9050
Total DCF retained by the Partnership with respect to period (5)		$	3,208			$	3,569
Distribution coverage ratio (6)			1.73	x			1.85	x

(1)	For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part II, Item 7.
(2)	Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.
(3)	Sustaining capital expenditures include cash payments and accruals applicable to the period.
(4)	See Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our quarterly cash distributions declared with respect to the years indicated.
(5)	Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts.  The retention of cash reduces our reliance on the capital markets.
(6)	Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.

		For the Year Ended December 31,
		2023				2022
Net cash flows provided by operating activities (GAAP)		$	7,569			$	8,039
Adjustments to reconcile net cash flows provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign):
Net effect of changes in operating accounts			555				54
Sustaining capital expenditures			(413	)			(372	)
Distributions received from unconsolidated affiliates attributable to the return of capital			42				98
Net income attributable to noncontrolling interests			(125	)			(125	)
Other, net			(90	)			(65	)
Operational DCF (non-GAAP)		$	7,538			$	7,629
Proceeds from asset sales and other matters			42				122
Monetization of interest rate derivative instruments accounted for as cash flow hedges			21				–
DCF (non-GAAP)		$	7,601			$	7,751

•

the first and second phase of our Texas Western Products System (first half of 2024);

•

our third natural gas processing train at Mentone in the Delaware Basin (first quarter of 2024);

•

our seventh natural gas processing train (“Leonidas”) in the Midland Basin (first quarter of 2024);

•

natural gas gathering expansion projects in the Delaware and Midland Basins (2024 and first half of 2025);

•

the expansion of our LPG and PGP export capacity at EHT (first half of 2025);

•

the Bahia NGL Pipeline (first half of 2025);

•

an NGL fractionator (“Frac 14”) and an associated DIB unit in Chambers County, Texas (second half of 2025);

•

our first natural gas processing train at our Mentone West location in the Delaware Basin (second half of 2025);

•

an eighth natural gas processing train (“Orion”) in the Midland Basin (second half of 2025);

•

an expansion of our Morgan’s Point terminal to increase ethylene export capacity (second half of 2024 and second half of 2025); and

•

our Neches River Ethane / Propane Export Facility located in Orange County, Texas (second half of 2025 and first half of 2026).

		For the Year Ended December 31,
		2023				2022
Capital investments for property, plant and equipment: (1)
Growth capital projects (2)		$	2,844			$	1,606
Sustaining capital projects (3)			422				358
Total		$	3,266			$	1,964
Cash used for business combinations, net (4)		$	–			$	3,204
Investments in unconsolidated affiliates		$	2			$	1

(1)	Growth and sustaining capital amounts presented in the table above are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our Statements of Consolidated Cash Flows.
(2)	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.
(3)	Sustaining capital projects 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. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method.
(4)	Amount for the year ended December 31, 2022 represents net cash used for the acquisition of our Midland Basin System, which closed in February 2022.

•

higher investments in natural gas gathering and processing projects in the Permian Basin (e.g., construction of six natural gas processing trains and related gathering systems), which accounted for a $761 million increase;

•

higher investments in ethane, ethylene and LPG export expansion projects at our Gulf Coast terminals, which accounted for a $295 million increase; and

•

higher investments in our Texas Western Products System, which accounted for a $245 million increase; partially offset by

•

lower investments in PDH 2 (placed into service in July 2023) at our Chambers County complex, which accounted for a $76 million decrease.

		Total				2024				2025				2026				2027				2028				Thereafter
Principal amount of debt obligations		$	29,021			$	1,300			$	1,150			$	1,625			$	575			$	1,000			$	23,371
Estimated cash payments for interest (1)		$	26,940			$	1,300			$	1,256			$	1,187			$	1,160			$	1,149			$	20,888

(1)

Estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2023, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are influenced by the long-term maturities of our $2.3 billion in junior subordinated notes (due June 2067 through February 2078).  The estimated cash payments assume that (i) the junior subordinated notes are not repaid prior to their respective maturity dates and (ii) the amount of interest paid on the junior subordinated notes is based on either (a) the current fixed interest rate charged or (b) the weighted-average variable rate paid in 2023, as applicable, for each note through the respective maturity date.

		Total				2024				2025				2026				2027				2028				Thereafter
Product purchase commitments		$	11,924			$	2,576			$	2,539			$	1,932			$	1,827			$	1,511			$	1,539

Selected asset information:
Current receivables from Non-Obligor Subsidiaries		$	2,569
Other current assets			5,416
Long-term receivables from Non-Obligor Subsidiaries			187
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $46.8 billion			9,185
Selected liability information:
Current portion of Guaranteed Debt, including interest of $455 million		$	1,755
Current payables to Non-Obligor Subsidiaries			1,567
Other current liabilities			4,239
Noncurrent portion of Guaranteed Debt, principal only			27,707
Noncurrent payables to Non-Obligor Subsidiaries			57
Other noncurrent liabilities			122
Mezzanine equity of Obligor Group:
Preferred units		$	49

Revenues from Non-Obligor Subsidiaries		$	17,344
Revenues from other sources			15,375
Operating income of Obligor Group			835
Net loss of Obligor Group, excluding equity in earnings of Non-Obligor Subsidiaries of $6.0 billion			(483	)

•

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.

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2022				December 31, 2023				January 31, 2024
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	90			$	7			$	10
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			97				6				9
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			83				8				11

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2022				December 31, 2023				January 31, 2024
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	18			$	39			$	(31	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(29	)			9				(64	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			64				69				2

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2022				December 31, 2023				January 31, 2024
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	53			$	66			$	8
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			24				(61	)			(97	)
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			81				193				113

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2022				December 31, 2023				January 31, 2024
Fair value assuming no change in underlying commodity prices	Asset (Liability)		$	(38	)		$	(9	)		$	(10	)
Fair value assuming 10% increase in underlying commodity prices	Asset (Liability)			(10	)			9				7
Fair value assuming 10% decrease in underlying commodity prices	Asset (Liability)			(63	)			(27	)			(27	)

(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.

/s/ A. James Teague			/s/ W. Randall Fowler
Name:	A. James Teague		Name:	W. Randall Fowler
Title:	Co-Chief Executive Officer		Title:	Co-Chief Executive Officer
	of Enterprise Products Holdings LLC			and Chief Financial Officer
				of Enterprise Products Holdings LLC

•

our strategic direction (including business opportunities through organic growth and acquisitions);

•

the vision, leadership and development of our management team;

•

our business goals and operational performance; and

•

strategies to preserve our financial strength.

Name	Age	Position with Enterprise GP
Randa Duncan Williams  (1,6)	62	Director and Chairman of the Board
Richard H. Bachmann (1,6)	71	Director and Vice Chairman of the Board
A. James Teague (1,6,7,8)	78	Director and Co-CEO
W. Randall Fowler (1,6,7,8)	67	Director, Co-CEO and CFO
Carin M. Barth (2,6)	61	Director
Murray E. Brasseux (4, 6)	75	Director
Rebecca G. Followill (4)	65	Director
James T. Hackett (2,3,6)	70	Director
William C. Montgomery (4,5)	62	Director
John R. Rutherford (2)	63	Director
Harry P. Weitzel (6,8)	59	Director and Executive Vice President, General Counsel and Secretary
Graham W. Bacon (8)	60	Executive Vice President and Chief Operating Officer
R. Daniel Boss (8)	48	Executive Vice President – Accounting, Risk Control and Information Technology
Christian M. Nelly (8)	48	Executive Vice President – Finance and Sustainability and Treasurer
Brent B. Secrest (8)	51	Executive Vice President and Chief Commercial Officer

(1)	Member of Office of the Chairman
(2)	Member of the Governance Committee
(3)	Chairman of the Governance Committee
(4)	Member of the Audit and Conflicts Committee
(5)	Chairman of the Audit and Conflicts Committee
(6)	Member of the Capital Projects Committee
(7)	Co-Chairman of the Capital Projects Committee
(8)	Executive officer

•

for Ms. Duncan Williams, legal and community involvement with numerous charitable organizations, and active involvement in EPCO’s businesses, including ownership in and management of our businesses;

•

for Mr. Teague, over 50 years of commercial management of midstream assets and marketing and trading activities, both for third parties and for us;

•

for Mr. Fowler, over 24 years of experience with our midstream assets, including finance, accounting and investor relations and, for over 18 years, as a member of our executive management team;

•

for Mr. Bachmann, over 40 years of experience with our midstream assets, including legal, regulatory, contracts and mergers and acquisitions and, for over 24 years, as a member of either EPCO’s or our executive management teams; and

•

for Mr. Weitzel, over 24 years of experience in Texas and California as a commercial litigator, having successfully represented individual, corporate and governmental clients as plaintiffs and defendants in a wide variety of business-related matters.

•

for Ms. Barth, executive management experience in various financial and governance roles;

•

for Mr. Brasseux, executive management experience in banking and finance as well as governance roles;

•

for Mrs. Followill, executive management experience in the financial services industry (including in the areas of analysis and assessing the valuations and competitiveness of public and private companies in the energy industry);

•

for Mr. Hackett, executive management of a major oil and gas exploration and production company;

•

for Mr. Montgomery, executive management of both an investment banking firm and a private equity investment firm serving the global energy industry; and

•

for Mr. Rutherford, executive management experience in the midstream energy industry (including in the areas of strategic planning, mergers and acquisitions, investment banking and finance).

				Equity-
		Cash		Based	All Other
Name and		Salary	Bonus	Awards	Compensation	Total
Principal Position	Year	($)	($)	($) (1)	($) (2)	($)
A. James Teague,	2023	$    1,149,500	$    3,700,000	$   7,740,000	$      1,377,039	$    13,966,539
Co-CEO	2022	1,075,000	3,700,000	6,386,500	6,192,313	17,353,813
	2021	987,500	3,200,000	5,197,500	1,031,514	10,416,514
W. Randall Fowler,	2023	862,125	2,775,000	5,805,000	4,773,863	14,215,988
Co-CEO and CFO	2022	806,250	2,775,000	4,789,875	872,614	9,243,739
	2021	731,250	2,400,000	3,898,125	753,389	7,782,764
Graham W. Bacon,	2023	593,750	825,000	3,336,500	1,617,939	6,373,189
Executive Vice President and	2022	563,000	825,000	2,289,500	532,326	4,209,826
Chief Operating Officer	2021	524,000	750,000	1,975,050	457,633	3,706,683
Brent B. Secrest,	2023	563,750	700,000	3,185,200	1,588,794	6,037,744
Executive Vice President and	2022	519,250	775,000	2,289,500	490,539	4,074,289
Chief Commercial Officer	2021	484,000	700,000	1,975,050	397,510	3,556,560
R. Daniel Boss,	2023	454,812	498,750	2,842,115	1,437,564	5,233,241
Executive Vice President – Accounting,
Risk Control and Information Technology

(1)	Amounts represent our estimated share of the aggregate grant date fair value of equity-based awards granted during each year presented.  See “ Grants of Equity-Based Awards in Fiscal Year 2023 ” within this Item 11 for information regarding awards granted in the year ended December 31, 2023.
(2)	Amounts include (i) contributions in connection with funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid on equity-based awards, (iii) the imputed value of life insurance premiums paid on behalf of the officer, (iv) employee retention payments and (v) other amounts.

Named Executive Officer		Contributions Under Funded, Qualified, Defined Contribution Retirement Plans				Distributions Paid On Equity-Based Awards (1)				Life Insurance Premiums				Employee Retention Payments (2)				Other				Total All Other Compensation
A. James Teague		$	39,600			$	1,315,775			$	13,596			$	–			$	8,068			$	1,377,039
W. Randall Fowler			29,700				983,708				6,286				3,750,000				4,169				4,773,863
Graham W. Bacon			39,600				565,873				4,356				1,000,000				8,110				1,617,939
Brent B. Secrest			39,600				542,476				1,518				1,000,000				5,200				1,588,794
R. Daniel Boss			34,485				447,339				941				950,000				4,799				1,437,564

(1)

Reflects aggregate cash payments made to the named executive officer in connection with (i) distribution equivalent rights (“DERs”) issued in tandem with phantom unit awards and (ii) distributions paid in connection with profits interest awards.  With respect to DER amounts allocated to us, the following cash payments were made to the named executive officers during the year ended December 31, 2023: Mr. Teague, $1,315,775; Mr. Fowler, $983,708; Mr. Bacon, $473,388; Mr. Secrest, $468,488; and Mr. Boss, $377,050.

(2)

Amounts presented for each of Messrs. Fowler, Bacon, Secrest and Boss relate to a four-year employee retention agreement that was settled in June 2023 and reflects the amount charged to us based on the percentage of time that each applicable named executive officer spent on our business and affairs since the retention agreement was originally executed.  For more information regarding employee retention agreements involving our named executive officers see “Compensation Discussion and Analysis” below.

					Grant
					Date Fair
					Value of
		Estimated Future Payouts Under			Equity-
		Equity Incentive Plan Awards			Based
	Grant	Threshold	Target	Maximum	Awards
Award Type/Named Executive Officer	Date	(#)	(#)	(#)	($) (1)
Phantom unit awards: (2)
A. James Teague	2/09/23	–	300,000	–	$   7,740,000
W. Randall Fowler	2/09/23	–	300,000	–	5,805,000
Graham W. Bacon	2/09/23	–	100,000	–	2,580,000
Brent B. Secrest	2/09/23	–	100,000	–	2,580,000
R. Daniel Boss	2/09/23	–	92,500	–	2,267,175
Profits interest awards: (3)
Graham W. Bacon	11/06/23	–	–	–	$   756,500
Brent B. Secrest	11/06/23	–	–	–	605,200
R. Daniel Boss	11/06/23	–	–	–	574,940

(1)	Amounts presented reflect that portion of grant date fair value allocable to us based on the estimated percentage of time each named executive officer spent on our consolidated business activities during 2023.  Based on current allocations, we estimate that the compensation expense we record for each named executive officer with respect to these awards will equal these amounts over time.
(2)	The grant date fair value presented for the phantom unit awards is based, in part, on the closing price of our common units on February 9, 2023 of $25.80 per unit.
(3)	Represents the incremental fair value of the modifications of Mr. Bacon’s, Mr. Secrest’s and Mr. Boss’s respective profits interest awards in EPD IV, computed as of the amendment date of November 6, 2023.

	Unit Awards
	Number of
	Units	Value
	Acquired on	Realized on
	Vesting	Vesting
Named Executive Officer	(#) (1)	($)
A. James Teague:
Vesting of phantom unit awards (2)	237,500	$         6,360,250
W. Randall Fowler:
Vesting of phantom unit awards (2)	229,000	$         6,132,620
Graham W. Bacon:
Vesting of phantom unit awards (2)	91,250	$         2,443,675
Brent B. Secrest:
Vesting of phantom unit awards (2)	81,250	$         2,175,875
R. Daniel Boss:
Vesting of phantom unit awards (2)	62,000	$         1,660,360

(1)	Represents the gross number of Partnership common units acquired upon vesting of phantom unit and profits interest awards, before adjustments for associated tax withholdings.
(2)	Value realized on vesting of the phantom unit awards determined by multiplying the gross number of Partnership common units received by the closing price of our common units on the date of vesting.

		Unit Awards
			Market
		Number	Value
		of Units	of Units
		That Have	That Have
		Not Vested	Not Vested
Award Type/Named Executive Officer		(#) (1)	($) (2,3)
Phantom unit awards: (4)
A. James Teague		680,000	$  17,918,000
W. Randall Fowler		680,000	17,918,000
Graham W. Bacon		241,250	6,356,938
Brent B. Secrest		241,250	6,356,938
R. Daniel Boss		208,000	5,480,800
Profits interest awards:
Graham W. Bacon:
EPD IV (5)		–	$                  –
Brent B. Secrest:
EPD IV (5)		–	–
R. Daniel Boss:
EPD IV (5)		–	–

(1)	Represents the total number of phantom unit awards outstanding for each named executive officer.
(2)	With respect to amounts presented for phantom unit awards, the market values were derived by multiplying the total number of awards outstanding for the named executive officer by the closing price of Partnership common units on December 29, 2023 (the last trading day of 2023) of $26.35 per unit.
(3)	With respect to amounts presented for the profits interest awards, amount represents the estimated liquidation value to be received by the named executive officer based on the closing price of Partnership common units on December 29, 2023 and the terms of liquidation outlined in the applicable Employee Partnership agreement.  There was no residual profits interest in any of the Employee Partnerships due to a decrease in the market value of the Partnership common units they own since the formation date of each respective Employee Partnership.
(4)	Of the 2,050,500 phantom unit awards presented in the table, the vesting schedule is as follows: 785,625 in 2024; 617,375 in 2025; 424,375 in 2026 and 223,125 in 2027.
(5)	With respect to EPD IV, the profits interest share held by Messrs. Bacon, Secrest and Boss at December 31, 2023 was approximately 5.78%, 4.62% and 4.62%, respectively.  The vesting date of the profits interests awards for EPD IV is the earliest of (i) December 3, 2027, (ii) the first date on or after November 6, 2023 for which the closing sale price of the Partnership’s common units on the NYSE is equal to or greater than $29.02 per unit (subject to certain adjustments), (iii) a change of control, or (iv) dissolution of such Employee Partnership.

•

First, a list was prepared of all active EPCO employees, excluding Mr. Teague, Mr. Fowler and those on long-term disability, that devote all or a substantial portion of their time to our consolidated businesses and affairs.   This list was based on employee information as of December 31, 2023. There are approximately 7,447 EPCO personnel who spend all or a substantial portion of their time engaged in our business.

•

Second, basic wage data for each active EPCO employee, excluding Mr. Teague, Mr. Fowler and those on long-term disability, was extracted from Form W-2 information provided to the Internal Revenue Service for fiscal 2023. This information was then sorted and the employee who earned the median compensation (the “median employee”) was selected from the list.

•

Third, once the median employee was selected, his or her respective total annual compensation for 2023 was determined using the same method used to determine Mr. Teague’s and Mr. Fowler’s total annual compensation for 2023 as presented in the Summary Compensation Table within this Part III, Item 11.

•

a $90,000 annual cash retainer and an annual grant of the Partnership’s common units having a fair market value of $90,000, based on the closing price of such common units on the trading day immediately preceding grant date;

•

a $2,500 per meeting cash fee for attendance at each meeting of the Board (other than a quarterly Board meeting);

•

a $2,500 per meeting cash fee for attendance at each meeting of a committee or subcommittee of which such director is a member (other than any committee or subcommittee meeting that occurs on the same day as (i) a Board meeting and/or (ii) a previous meeting of a committee or subcommittee of which such director is a member);

•

if the individual served as a chairman of the Audit and Conflicts Committee, an additional $25,000 annual cash retainer; and

•

if the individual served as a chairman of the Governance Committee, an additional $20,000 annual cash retainer.

		Fees Earned				Value of
		or Paid				Equity-Based
		in Cash				Awards				Total
Independent Voting Director		($)				($)				($)
Carin M. Barth		$	95,000			$	90,000			$	185,000
Murray E. Brasseux			110,000				90,000				200,000
Rebecca G. Followill			110,000				90,000				200,000
James T. Hackett (1)			115,000				90,000				205,000
William C. Montgomery (2)			135,000				90,000				225,000
John R. Rutherford			92,500				90,000				182,500

(1)	Mr. Hackett serves as chairman of the Governance Committee.
(2)	Mr. Montgomery serves as chairman of the Audit and Conflicts Committee.

		Amount and
		Nature of
Name and Address		Beneficial	Percent
of Beneficial Owner	Title of Class	Ownership	of Class
Randa Duncan Williams (1)	Common Units	702,452,294	32.4%
1100 Louisiana Street, 10 th Floor
Houston, Texas 77002

(1)	For a detailed listing of the ownership amounts that comprise Ms. Duncan Williams’ total beneficial ownership of the Partnership’s common units, see the table presented in the following section, “ Security Ownership of Management ,” within this Part III, Item 12.

				Amount and
		Positions with		Nature Of
		Enterprise GP		Beneficial		Percent of
		at February 16, 2024		Ownership		Class
Randa Duncan Williams:		Director and Chairman of the Board
Units controlled by EPCO Voting Trust:
Through EPCO				74,754,703		3.4%
Through EPCO Holdings, Inc.				597,110,600		27.5%
Through Employee Partnerships				8,000,000		*
Units controlled by Alkek and Williams, Ltd.				558,315		*
Units controlled by Chaswil, Ltd.				92,913		*
Units controlled by family trusts (1)				21,070,501		*
Units owned personally (2)				865,262		*
Total for Randa Duncan Williams				702,452,294		32.4%

* Represents a beneficial ownership of less than 1% of class
(1)	The number of common units presented for Ms. Duncan Williams includes common units held by family trusts for which she serves as a director of an entity trustee but has disclaimed beneficial ownership (except to the extent of her pecuniary interest therein).
(2)	The number of common units presented for Ms. Duncan Williams includes 9,090 common units held by her spouse and 4,040 common units held jointly with her spouse.

				Common Units
				Amount and
		Positions with		Nature Of
		Enterprise GP		Beneficial		Percent of
		at February 16, 2024		Ownership		Class
Richard H. Bachmann		Director and Vice Chairman of the Board		2,013,767		*
A. James Teague (1,2)		Director and Co-CEO		2,798,764		*
W. Randall Fowler (1,3)		Director, Co-CEO and CFO		2,147,320		*
Carin M. Barth (4)		Director		101,737		*
Murray E. Brasseux (5)		Director		39,034		*
Rebecca G. Followill (6)		Director		8,244		*
James T. Hackett (7)		Director		305,974		*
William C. Montgomery		Director		118,187		*
John R. Rutherford		Director		150,853		*
Harry P. Weitzel		Director and Executive Vice President, General Counsel and Secretary		239,761		*
Graham W. Bacon (1)		Executive Vice President and Chief Operating Officer		538,307		*
Brent B. Secrest (1)		Executive Vice President and Chief Commercial Officer		304,882		*
R. Daniel Boss (1)		Executive Vice President – Accounting,     Risk Control and Information Technology		217,956		*
All directors and executive officers (including all named executive officers) of Enterprise GP, as a group (15 individuals in total)				711,638,754		32.8%

* Represents a beneficial ownership of less than 1% of class
(1)	These individuals are named executive officers for the year ended December 31, 2023.
(2)	The number of common units presented for Mr. Teague includes (i) 70,731 common units held by a trust, (ii) 41,155 common units held by his spouse and (iii) 6,060 common units held by minor children.
(3)	The number of common units presented for Mr. Fowler includes (i) 708,419 common units held by a family limited partnership (for which he has disclaimed beneficial ownership except to the extent of his pecuniary interest) and (ii) 2,339 common units held by his spouse.
(4)	The number of common units presented for Ms. Barth includes 19,050 common units held for the benefit of her parents (for which she has disclaimed beneficial ownership except to the extent of her pecuniary interest).
(5)	The number of common units presented for Mr. Brasseux includes 2,882 common units held by his spouse.
(6)	The number of common units presented for Mrs. Followill includes 1,200 common units held for the benefit of her mother-in-law (for which she has disclaimed beneficial ownership except to the extent of her pecuniary interest).
(7)	The number of common units presented for Mr. Hackett includes (i) 10,215 common units held by family trusts and (ii) 34,897 common units held by a family limited partnership.

•

each non-management director of Enterprise GP is required to own our 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 Enterprise GP is required to own our 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.

				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	of Outstanding	securities
		Common Unit	Common Unit	reflected in
Plan Category		Options	Options	column (a))
		(a)	(b)	(c)
Equity compensation plans approved by unitholders:
2008 Plan (1)		–	–	109,102,487
Equity compensation plans not approved by unitholders:
None		–	–	–
Total for equity compensation plans		–	–	109,102,487

(1)	At December 31, 2023, the total number of common units authorized for issuance under the 2008 Plan was 165,000,000 common units.

•

pursuant to our partnership agreement or the limited liability company agreement of Enterprise GP, as such agreements may be amended from time to time, including without limitation for the purpose of obtaining “Special Approval” (as described below);

•

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 an interest that is financially material to such officer, director or immediate family member (as applicable) or is otherwise a named party;

•

when requested to do so by management or the Board;

•

in accordance with and to the extent required under Rule 314.00 of the Listed Company Manual of the NYSE;

•

with a value of $5 million or more (unless such transaction is equivalent to an arm’s length transaction with a third party); or

•

that it may otherwise deem appropriate from time to time.

•

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.

•

assessing the business rationale for the transaction;

•

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.

		For the Year Ended December 31,
		2023				2022
Audit fees (1)		$	5,386,633			$	5,398,000

(1)	Audit fees for 2023 and 2022 include $67,500 and $40,000, respectively, of charges for audit-related projects that were reimbursed by business partners.

(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).
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).
2.14	Amendment No. 1 dated as of June 6, 2018 to Contribution and Purchase Agreement, by and among Enterprise Products Partners L.P., Oiltanking Holding Americas, Inc., Enterprise Products Holdings LLC and Marquard & Bahls, AG (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 12, 2018).
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	Seventh Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated as of September 30, 2020 (incorporated by reference to Exhibit 3.1 to Form 8-K filed October 1, 2020).
3.4	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).
3.5	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).
3.6	Sixth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of August 9, 2022 (incorporated by reference to Exhibit 3.9 to Form 10-Q filed August 9, 2022).
3.7	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).
3.8	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).
3.9	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 October 1, 2020).
4.2	Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.2 to Form 10-K filed February 28, 2020).
4.3	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 14, 2000).
4.4	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).

4.5	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).
4.6	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).
4.7	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	Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
4.9	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).
4.10	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).
4.11	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).
4.12	Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.13	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).
4.14	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).
4.15	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).
4.16	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).
4.17	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).

4.18	Twenty-Fourth Supplemental Indenture, dated as of March 18, 2013, 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 March 18, 2013).
4.19	Twenty-Fifth Supplemental Indenture, dated as of February 12, 2014, 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 February 12, 2014).
4.20	Twenty-Sixth Supplemental Indenture, dated as of October 14, 2014, 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 October 14, 2014).
4.21	Twenty-Seventh Supplemental Indenture, dated as of May 7, 2015, 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 7, 2015).
4.22	Twenty-Eighth Supplemental Indenture, dated as of April 13, 2016, 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 13, 2016).
4.23	Twenty-Ninth Supplemental Indenture, dated as of August 16, 2017, 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 16, 2017).
4.24	Thirtieth Supplemental Indenture, dated as of February 15, 2018, 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 February 15, 2018).
4.25	Thirty-First Supplemental Indenture, dated as of February 15, 2018, 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 February 15, 2018).
4.26	Thirty-Second Supplemental Indenture, dated as of October 11, 2018, 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 11, 2018).
4.27	Thirty-Third Supplemental Indenture, dated as of July 8, 2019, 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 July 8, 2019).
4.28	Thirty-Fourth Supplemental Indenture, dated as of January 15, 2020, 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 15, 2020).
4.29	Thirty-Fifth Supplemental Indenture, dated as of August 7, 2020, 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 August 7, 2020).
4.30	Thirty-Sixth Supplemental Indenture, dated as of September 15, 2021, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Wells Fargo Bank, National Association, as Original Trustee, and U.S. Bank National Association, as Series Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed September 15, 2021).

4.31	Thirty-Seventh Supplemental Indenture, dated as of January 10, 2023, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and U.S. Bank Trust Company, National Association, as Series Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.32	Thirty-Eighth Supplemental Indenture, dated as of January 11, 2024, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and U.S. Bank Trust Company, National Association, as Series Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 11, 2024).
4.33	Form of Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 10-K filed March 31, 2003).
4.34	Form of Global Note representing $350 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).
4.35	Form of Global Note representing $250 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).
4.36	Form of Global Note representing $600 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 5, 2009).
4.37	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 E to Exhibit 4.1 to Form 8-K filed October 28, 2009).
4.38	Form of Global Note representing $285.8 million principal amount of Junior Subordinated Notes due 2067 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.2 to Form 8-K filed October 28, 2009).
4.39	Form of Global Note representing $600 million principal amount of 6.45% Senior Notes due 2040 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 20, 2010).
4.40	Form of Global Note representing $750 million principal amount of 5.95% Senior Notes due 2041 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 13, 2011).
4.41	Form of Global Note representing $600 million principal amount of 5.70% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 24, 2011).
4.42	Form of Global Note representing $750 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.25 to Form 10-Q filed May 10, 2012).
4.43	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 B to Exhibit 4.3 to Form 8-K filed August 13, 2012).
4.44	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 A to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.45	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 B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.46	Form of Global Note representing $850 million principal amount of 3.90% Senior Notes due 2024 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 12, 2014).
4.47	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 B to Exhibit 4.3 to Form 8-K filed February 12, 2014).

4.48	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 B to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.49	Form of Global Note representing $400 million principal amount of 4.95% Senior Notes due 2054 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.4 to Form 8-K filed October 14, 2014).
4.50	Form of Global Note representing $400 million principal amount of 4.85% Senior Notes due 2044 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed March 18, 2013).
4.51	Form of Global Note representing $875 million principal amount of 3.70% Senior Notes due 2026 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.52	Form of Global Note representing $875 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.53	Form of Global Note representing $575 million principal amount of 3.95% Senior Notes due 2027 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed April 13, 2016).
4.54	Form of Global Note representing $100 million principal amount of 4.90% Senior Notes due 2046 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed May 7, 2015).
4.55	Form of Global Note representing $700 million principal amount of Junior Subordinated Notes D due 2077 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.56	Form of Global Note representing $1.0 billion principal amount of Junior Subordinated Notes E due 2077 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed August 16, 2017).
4.57	Form of Global Note representing $1.25 billion principal amount of 4.25% Senior Notes due 2048 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed February 15, 2018).
4.58	Form of Global Note representing $700 million principal amount of Junior Subordinated Notes F due 2078 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed February 15, 2018).
4.59	Form of Global Note representing $1.0 billion principal amount of 4.15% Senior Notes due 2028 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.60	Form of Global Note representing $1.25 billion principal amount of 4.80% Senior Notes due 2049 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed October 11, 2018).
4.61	Form of Global Note representing $1.25 billion principal amount of 3.125% Senior Notes due 2029 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.62	Form of Global Note representing $1.25 billion principal amount of 4.200% Senior Notes due 2050 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed July 8, 2019).
4.63	Form of Global Note representing $1.0 billion principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.64	Form of Global Note representing $1.0 billion principal amount of 3.700% Senior Notes due 2051 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.3 to Form 8-K filed January 15, 2020).

4.65	Form of Global Note representing $1.0 billion principal amount of 3.950% Senior Notes due 2060 with attached Guarantee (incorporated by reference to Exhibit C to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.66	Form of Global Note representing $250 million principal amount of 2.800% Senior Notes due 2030 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed January 15, 2020).
4.67	Form of Global Note representing $1.0 billion principal amount of 3.200% Senior Notes due 2052 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed August 7, 2020).
4.68	Form of Global Note representing $1.0 billion principal amount of 3.300% Senior Notes due 2053 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.3 to Form 8-K filed September 15, 2021).
4.69	Form of Global Note representing $750 million principal amount of 5.050% Senior Notes due 2026 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.70	Form of Global Note representing $1.0 billion principal amount of 5.350% Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed January 10, 2023).
4.71	Form of Global Note representing $1.0 billion principal amount of 4.600% Senior Notes due 2027 with attached Guarantee (incorporated by reference to Exhibit A to Exhibit 4.4 to Form 8-K filed January 11, 2024).
4.72	Form of Global Note representing $1.0 billion principal amount of 4.850% Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit B to Exhibit 4.4 to Form 8-K filed January 11, 2024).
4.73	Replacement Capital Covenant, dated October 27, 2009, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).
4.74	Amendment to Replacement Capital Covenants, dated May 6, 2015, executed by Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.59 to Form 10-Q filed May 8, 2015).
4.75	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).
4.76	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).
4.77	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).
4.78	Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
4.79	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).

4.80	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 March 1, 2010).
4.81	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).
4.82	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).
4.83	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).
4.84	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).
4.85	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 March 1, 2010).
4.86	Specimen Unit Certificate for the Series A Cumulative Convertible Preferred Units, (incorporated by reference to Exhibit B to Exhibit 3.1 to Form 8-K filed October 1, 2020).
4.87	Registration Rights Agreement, dated as of September 30, 2020, by and among Enterprise Products Partners L.P. and the Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 1, 2020).
10.1***	2008 Enterprise Products Long-Term Incentive Plan (Fourth Amendment and Restatement) (incorporated by reference to Annex A to Definitive Proxy Statement filed October 24, 2022).
10.2***	Form of Employee Phantom Unit Grant Award under the 2008 Enterprise Products Long-Term Incentive Plan for awards issued before February 3, 2021 (incorporated by reference to Exhibit 10.4 to Form 10-K filed February 24, 2017).
10.3***	Form of Employee Phantom Unit Grant Award under the 2008 Enterprise Products Long-Term Incentive Plan for awards issued on or after February 3, 2021 and before November 22, 2022 (incorporated by reference to Exhibit 10.3 to Form 10-K filed March 1, 2021).
10.4***	Form of Employee Phantom Unit Grant Award under the 2008 Enterprise Products Long-Term Incentive Plan for awards issued on or after November 22, 2022 (incorporated by reference to Exhibit 10.4 to Form 10-K filed February 28, 2023).
10.5	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 February 13, 2015).

10.6	364-Day Revolving Credit Agreement, dated as of March 31, 2023, by and among Enterprise Products Operating LLC, as Borrower, the Lenders party thereto, Citibank, N.A., as Administrative Agent, and certain financial institutions named therein, as Co-Syndication Agents and Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed March 31, 2023).
10.7	Guaranty Agreement, dated as of March 31, 2023, 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 March 31, 2023).
10.8	Revolving Credit Agreement, dated as of March 31, 2023, by and among Enterprise Products Operating LLC, as Borrower, the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, and certain financial institutions named therein, as Co-Syndication Agents and Co-Documentation Agents (incorporated by reference to Exhibit 10.3 to Form 8-K filed March 31, 2023).
10.9	Guaranty Agreement, dated as of March 31, 2023, by Enterprise Products Partners L.P. in favor of Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.4 to Form 8-K filed March 31, 2023).
10.10***	EPD 2018 Unit IV L.P. Agreement of Limited Partnership dated December 3, 2018 (incorporated by reference to Exhibit 10.1 to Form 8-K filed December 6, 2018).
10.11***	EPCO Unit II L.P. Agreement of Limited Partnership dated December 3, 2018 (incorporated by reference to Exhibit 10.2 to Form 8-K filed December 6, 2018).
10.12***	Amendment No. 1 to Agreement of Limited Partnership of EPD 2018 Unit IV L.P., dated as of November 6, 2023 (incorporated by reference to Exhibit 10.2 to Form 10-Q filed November 9, 2023).
10.13***	Amendment No. 1 to Agreement of Limited Partnership of EPCO Unit II L.P., dated as of November 6, 2023 (incorporated by reference to Exhibit 10.3 to Form 10-Q filed November 9, 2023).
10.14	Series A Cumulative Convertible Preferred Unit Purchase Agreement, dated as of September 30, 2020, by and among Enterprise Products Partners L.P. and the Purchasers party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 1, 2020).
10.15	Securities Exchange Agreement, dated as of September 30, 2020, by and between Enterprise Products Partners L.P. and OTA Holdings, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K filed October 1, 2020).
10.16	Equity Distribution Agreement, dated September 15, 2023, by and among Enterprise Products Partners L.P., Citigroup Global Markets Inc., Barclays Capital Inc., BBVA Securities Inc., BMO Capital Markets Corp., BofA Securities, Inc., Credit Agricole Securities (USA) Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC, Mizuho Securities USA LLC, Morgan Stanley & Co. LLC, MUFG Securities Americas Inc., RBC Capital Markets, LLC, Scotia Capital (USA) Inc., SG Americas Securities, LLC, TD Securities (USA) LLC, Truist Securities, Inc. and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 1.1 to Form 8-K filed September 15, 2023).
10.17***	Retention Bonus Agreement between A. James Teague and Enterprise Products Company dated effective April 15, 2019 (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 18, 2019).
10.18***	Retention Bonus Agreement between W. Randall Fowler and Enterprise Products Company dated effective April 15, 2019 (incorporated by reference to Exhibit 10.2 to Form 8-K filed April 18, 2019).
10.19***	Retention Bonus Agreement between Graham W. Bacon and Enterprise Products Company dated effective April 15, 2019 (incorporated by reference to Exhibit 10.3 to Form 8-K filed April 18, 2019).
10.20***	Retention Bonus Agreement between Brent B. Secrest and Enterprise Products Company dated effective April 15, 2019 (incorporated by reference to Exhibit 10.4 to Form 8-K filed April 18, 2019).
10.21***#	Retention Bonus Agreement between R. Daniel Boss and Enterprise Products Company dated effective April 15, 2019.

21.1#		List of Consolidated Subsidiaries as of February 1, 2024.
22.1#		List of Issuers of Debt Securities Guaranteed by Enterprise Products Partners L.P. and Associated Securities at December 31, 2023.
23.1#		Consent of Deloitte & Touche LLP.
31.1#		Sarbanes-Oxley Section 302 certification of A. James Teague for Enterprise Products Partners L.P.’s annual report on Form 10-K for the year ended December 31, 2023.
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, 2023.
32.1#		Sarbanes-Oxley Section 906 certification of A. James Teague for Enterprise Products Partners L.P.’s annual report on Form 10-K for the year ended December 31, 2023.
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, 2023.
97.1#		Enterprise Products Partners L.P. Policy on Recoupment of Incentive Compensation.
101#		Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) in this Form 10-K include the: (i) Consolidated Balance Sheets, (ii) Statements of Consolidated Operations, (iii) Statements of Consolidated Comprehensive Income, (iv) Statements of Consolidated Cash Flows, (v) Statements of Consolidated Equity and (vi) Notes to the Consolidated Financial Statements.
104#		Cover Page Interactive Data File (embedded within the Inline XBRL 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.

ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)
By:	Enterprise Products Holdings LLC, as General Partner
By:	/s/ R. Daniel Boss
Name:	R. Daniel Boss
Title:	Executive Vice President – Accounting, Risk Control and Information Technology of the General Partner

Signature		Title (Position with Enterprise Products Holdings LLC)
/s/ Randa Duncan Williams		Director and Chairman of the Board
Randa Duncan Williams
/s/ Richard H. Bachmann		Director and Vice-Chairman of the Board
Richard H. Bachmann
/s/ A. James Teague		Director and Co-Chief Executive Officer
A. James Teague
/s/ W. Randall Fowler		Director, Co-Chief Executive Officer and Chief Financial Officer
W. Randall Fowler
/s/ Harry P. Weitzel		Director and Executive Vice President, General Counsel and Secretary
Harry P. Weitzel
/s/ Carin M. Barth		Director
Carin M. Barth
/s/ Murray E. Brasseux		Director
Murray E. Brasseux
/s/ Rebecca G. Followill		Director
Rebecca G. Followill
/s/ James T. Hackett		Director
James T. Hackett
/s/ William C. Montgomery		Director
William C. Montgomery
/s/ John R. Rutherford		Director
John R. Rutherford
/s/ R. Daniel Boss		Executive Vice President – Accounting, Risk Control and Information Technology
R. Daniel Boss

		Page No.
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34 )		F-2
Consolidated Balance Sheets as of December 31, 2023 and 2022		F-4
Statements of Consolidated Operations for the Years Ended December 31, 2023 , 2022 and 2021		F-5
Statements of Consolidated Comprehensive Income for the Years Ended December 31, 2023 , 2022 and 2021		F-6
Statements of Consolidated Cash Flows for the Years Ended December 31, 2023 , 2022 and 2021		F-7
Statements of Consolidated Equity for the Years Ended December 31, 2023 , 2022 and 2021		F-8
Notes to Consolidated Financial Statements
	Note 1   – Partnership Organization and Operations	F-10
	Note 2   – Summary of Significant Accounting Policies	F-10
	Note 3   – Inventories	F-19
	Note 4   – Property, Plant and Equipment	F-20
	Note 5   – Investments in Unconsolidated Affiliates	F-22
	Note 6   – Intangible Assets and Goodwill	F-24
	Note 7   – Debt Obligations	F-27
	Note 8   – Capital Accounts	F-31
	Note 9   – Revenues	F-36
	Note 10 – Business Segments and Related Information	F-40
	Note 11 – Earnings Per Unit	F-45
	Note 12 – Business Combinations	F-46
	Note 13 – Equity-Based Awards	F-47
	Note 14 – Hedging Activities and Fair Value Measurements	F-51
	Note 15 – Related Party Transactions	F-59
	Note 16 – Income Taxes	F-61
	Note 17 – Commitments and Contingent Liabilities	F-63
	Note 18 – Significant Risks and Uncertainties	F-66
	Note 19 – Supplemental Cash Flow Information	F-68
	Note 20 – Subsequent Event s	F-69

		December 31,
		2023				2022
ASSETS
Current assets:
Cash and cash equivalents		$	180			$	76
Restricted cash			140				130
Accounts receivable – trade, net of allowance for credit losses of $ 35 at December 31, 2023 and $ 54 at December 31, 2022			7,765				6,964
Accounts receivable – related parties			7				11
Inventories (see Note 3)			3,352				2,554
Derivative assets (see Note 14)			347				469
Prepaid and other current assets			457				394
Total current assets			12,248				10,598
Property, plant and equipment, net (see Note 4)			45,804				44,401
Investments in unconsolidated affiliates (see Note 5)			2,330				2,352
Intangible assets, net (see Note 6)			3,770				3,965
Goodwill (see Note 6)			5,608				5,608
Other assets			1,222				1,184
Total assets		$	70,982			$	68,108
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of debt (see Note 7)		$	1,300			$	1,744
Accounts payable – trade			1,195				743
Accounts payable – related parties			199				232
Accrued product payables			8,911				7,988
Accrued interest			455				426
Derivative liabilities (see Note 14)			396				354
Other current liabilities			675				778
Total current liabilities			13,131				12,265
Long-term debt (see Note 7)			27,448				26,551
Deferred tax liabilities (see Note 16)			611				600
Other long-term liabilities			984				941
Commitments and contingent liabilities (see Note 17)
Redeemable preferred limited partner interests: (see Note 8)
Series A cumulative convertible preferred units (“preferred units”) ( 50,412 units outstanding at December 31, 2023 and December 31, 2022 )			49				49
Equity: (see Note 8)
Partners’ equity:
Common limited partner interests ( 2,168,245,238 units issued and outstanding at December 31, 2023 and 2,170,806,347 units issued and outstanding at December 31, 2022 )			28,663				27,555
Treasury units, at cost			( 1,297	)			( 1,297	)
Accumulated other comprehensive income			307				365
Total partners’ equity			27,673				26,623
Noncontrolling interests in consolidated subsidiaries			1,086				1,079
Total equity			28,759				27,702
Total liabilities, preferred units, and equity		$	70,982			$	68,108

		For the Year Ended December 31,
		2023				2022				2021
Revenues:
Third parties		$	49,654			$	58,127			$	40,727
Related parties			61				59				80
Total revenues (see Note 9)			49,715				58,186				40,807
Costs and expenses:
Operating costs and expenses:
Third party and other costs			41,632				50,160				33,791
Related parties			1,385				1,342				1,287
Total operating costs and expenses			43,017				51,502				35,078
General and administrative costs:
Third party and other costs			75				85				75
Related parties			156				156				134
Total general and administrative costs			231				241				209
Total costs and expenses (see Note 10)			43,248				51,743				35,287
Equity in income of unconsolidated affiliates			462				464				583
Operating income			6,929				6,907				6,103
Other income (expense):
Interest expense			( 1,269	)			( 1,244	)			( 1,283	)
Interest income			27				11				5
Other, net			14				23				–
Total other expense, net			( 1,228	)			( 1,210	)			( 1,278	)
Income before income taxes			5,701				5,697				4,825
Provision for income taxes (see Note 16)			( 44	)			( 82	)			( 70	)
Net income			5,657				5,615				4,755
Net income attributable to noncontrolling interests (see Note 8)			( 125	)			( 125	)			( 117	)
Net income attributable to preferred units (see Note 8)			( 3	)			( 3	)			( 4	)
Net income attributable to common unitholders		$	5,529			$	5,487			$	4,634
Earnings per unit: (see Note 11)
Basic earnings per common unit		$	2.52			$	2.50			$	2.11
Diluted earnings per common unit		$	2.52			$	2.50			$	2.10

		For the Year Ended December 31,
		2023				2022				2021
Net income		$	5,657			$	5,615			$	4,755
Other comprehensive income (loss):
Cash flow hedges: (see Note 14)
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges			93				254				( 678	)
Reclassification of losses (gains) to net income			( 110	)			( 220	)			908
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges			( 36	)			26				183
Reclassification of losses (gains) to net income			( 5	)			19				38
Total cash flow hedges			( 58	)			79				451
Total other comprehensive income (loss)			( 58	)			79				451
Comprehensive income			5,599				5,694				5,206
Comprehensive income attributable to noncontrolling interests			( 125	)			( 125	)			( 117	)
Comprehensive income attributable to preferred units (see Note 8)			( 3	)			( 3	)			( 4	)
Comprehensive income attributable to common unitholders		$	5,471			$	5,566			$	5,085

		For the Year Ended December 31,
		2023				2022				2021
Operating activities:
Net income		$	5,657			$	5,615			$	4,755
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation and accretion			1,871				1,797				1,723
Amortization of intangible assets			201				177				151
Amortization of major maintenance costs for reaction-based plants			64				51				27
Other amortization expense			207				220				239
Impairment of assets other than goodwill (see Notes 2 and 4)			32				53				233
Equity in income of unconsolidated affiliates			( 462	)			( 464	)			( 583	)
Distributions received from unconsolidated affiliates attributable to earnings			446				446				544
Net losses (gains) attributable to asset sales and related matters (see Note 19)			( 10	)			1				5
Deferred income tax expense			12				60				40
Change in fair market value of derivative instruments			33				78				( 27	)
Non-cash expense related to long-term operating leases (see Note 17)			72				59				41
Net effect of changes in operating accounts (see Note 19)			( 555	)			( 54	)			1,366
Other operating activities			1				–				( 1	)
Net cash flows provided by operating activities			7,569				8,039				8,513
Investing activities:
Capital expenditures			( 3,266	)			( 1,964	)			( 2,223	)
Cash used for business combinations, net of cash received (see Note 12)			–				( 3,204	)			–
Investments in unconsolidated affiliates			( 2	)			( 1	)			( 2	)
Distributions received from unconsolidated affiliates attributable to the return of capital			42				98				46
Proceeds from asset sales and other matters (see Note 19)			42				122				64
Other investing activities			( 13	)			( 5	)			( 20	)
Cash used in investing activities			( 3,197	)			( 4,954	)			( 2,135	)
Financing activities:
Borrowings under debt agreements			89,899				96,140				11,159
Repayments of debt			( 89,447	)			( 97,395	)			( 11,492	)
Debt issuance costs			( 17	)			( 1	)			( 15	)
Monetization of interest rate derivative instruments (see Note 14)			21				–				75
Cash distributions paid to common unitholders (see Note 8)			( 4,301	)			( 4,095	)			( 3,930	)
Cash payments made in connection with distribution equivalent rights			( 38	)			( 34	)			( 31	)
Cash distributions paid to noncontrolling interests (see Note 8)			( 160	)			( 163	)			( 154	)
Cash contributions from noncontrolling interests (see Note 8)			44				7				72
Repurchase of common units under 2019 Buyback Program (see Note 8)			( 188	)			( 250	)			( 214	)
Other financing activities			( 71	)			( 53	)			( 41	)
Cash used in financing activities			( 4,258	)			( 5,844	)			( 4,571	)
Net change in cash and cash equivalents, including restricted cash			114				( 2,759	)			1,807
Cash and cash equivalents, including restricted cash, January 1			206				2,965				1,158
Cash and cash equivalents, including restricted cash, December 31		$	320			$	206			$	2,965

		Partners’ Equity
		Common Limited Partner Interests				Treasury Units				Accumulated Other Comprehensive Income (Loss)				Noncontrolling Interests in Consolidated Subsidiaries				Total
Balance, December 31, 2020		$	25,767			$	( 1,297	)		$	( 165	)		$	1,073			$	25,378
Net income			4,634				–				–				117				4,751
Cash distributions paid to common unitholders			( 3,930	)			–				–				–				( 3,930	)
Cash payments made in connection with distribution equivalent rights			( 31	)			–				–				–				( 31	)
Cash distributions paid to noncontrolling interests			–				–				–				( 154	)			( 154	)
Cash contributions from noncontrolling interests			–				–				–				72				72
Repurchase and cancellation of common units under 2019 Buyback Program			( 214	)			–				–				–				( 214	)
Amortization of fair value of equity-based awards			151				–				–				–				151
Cash flow hedges			–				–				451				–				451
Other, net			( 37	)			–				–				2				( 35	)
Balance, December 31, 2021			26,340				( 1,297	)			286				1,110				26,439
Net income			5,487				–				–				125				5,612
Cash distributions paid to common unitholders			( 4,095	)			–				–				–				( 4,095	)
Cash payments made in connection with distribution equivalent rights			( 34	)			–				–				–				( 34	)
Cash distributions paid to noncontrolling interests			–				–				–				( 163	)			( 163	)
Cash contributions from noncontrolling interests			–				–				–				7				7
Repurchase and cancellation of common units under 2019 Buyback Program			( 250	)			–				–				–				( 250	)
Amortization of fair value of equity-based awards			156				–				–				–				156
Cash flow hedges			–				–				79				–				79
Other, net			( 49	)			–				–				–				( 49	)
Balance, December 31, 2022			27,555				( 1,297	)			365				1,079				27,702
Net income			5,529				–				–				125				5,654
Cash distributions paid to common unitholders			( 4,301	)			–				–				–				( 4,301	)
Cash payments made in connection with distribution equivalent rights			( 38	)			–				–				–				( 38	)
Cash distributions paid to noncontrolling interests			–				–				–				( 160	)			( 160	)
Cash contributions from noncontrolling interests			–				–				–				44				44
Repurchase and cancellation of common units under 2019 Buyback Program			( 188	)			–				–				–				( 188	)
Amortization of fair value of equity-based awards			170				–				–				–				170
Cash flow hedges			–				–				( 58	)			–				( 58	)
Other, net			( 64	)			–				–				( 2	)			( 66	)
Balance, December 31, 2023		$	28,663			$	( 1,297	)		$	307			$	1,086			$	28,759