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 | ||
/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. |
Total Gas | |||||||||||
Net Gas | Processing | Net Gas | Total Gas | ||||||||
Production | Processing | Capacity | Production | No. of | Processing | Processing | |||||
Region | Ownership | Capacity | of Plant | Region | Ownership | Processing | Capacity | Capacity | |||
Facility Name | Location | Served | Interest | (MMcf/d) (1) | (MMcf/d) | ||||||
Description of Asset | Location | Served | Interest | Trains (1) | (MMcf/d) | (MMcf/d) (2) | |||||
Rocky Mountains | |||||||||||
Meeker | Colorado | Piceance | 100.0% | 1,800 | 1,800 | 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% | 1,050 | 1,050 | 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% | 900 | 900 | Texas | Delaware | 100.0% | 3 | 900 | 900 |
Pioneer | Wyoming | Green River | 100.0% | 800 | 800 | ||||||
Pascagoula | Mississippi | Gulf of Mexico | 75.0% (2) | 750 | 1,000 | ||||||
Chaco | New Mexico | San Juan | 100.0% | 600 | 600 | ||||||
Sea Robin | Louisiana | Gulf of Mexico | 71.0% (3) | 462 | 650 | ||||||
Neptune | Louisiana | Gulf of Mexico | 66.0% (3) | 429 | 650 | ||||||
Thompsonville | Texas | Eagle Ford | 100.0% | 330 | 330 | ||||||
Carthage (4) | Texas | Cotton Valley | 100.0% | 320 | 320 | ||||||
Mentone | Texas | Delaware | 100.0% | 300 | 300 | Texas | Delaware | 100.0% | 2 | 600 | 600 |
Shoup | Texas | Eagle Ford | 100.0% | 280 | 280 | ||||||
San Martin | Texas | Eagle Ford | 100.0% | 200 | 200 | ||||||
South Eddy | New Mexico | Delaware | 100.0% | 200 | 200 | New Mexico | Delaware | 100.0% | 1 | 200 | 200 |
Waha | Texas | Delaware | 100.0% | 150 | 150 | Texas | Delaware | 100.0% | 1 | 150 | 150 |
Sonora | Texas | Strawn | 100.0% | 120 | 120 | ||||||
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 | 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) | 98 | 750 | 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% (3) | 90 | 120 | Texas | Wilcox-Woodbine | 75.0% (4) | 1 | 75 | 100 |
Chaparral | New Mexico | Delaware | 100.0% | 45 | 45 | ||||||
Total | 8,924 | 10,265 | 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 |
(2) | Total gas processing capacity |
We own a 75% consolidated interest in the Pascagoula facility through our majority owned subsidiary, Pascagoula Gas Processing LLC. | |
We proportionately consolidate our undivided interests in these operating assets. | |
(5) | Our 13.1% ownership in |
Pipeline | Pipeline | |||||
Ownership | Length | Ownership | Length | |||
Description of Asset | Location(s) | Interest | (Miles) | Location(s) | Interest | (Miles) |
Mid-America Pipeline System (1) | Midwest and Western U.S. | 100.0% | 7,862 | Midwest and Western U.S. | 100.0% | 7,850 |
South Texas NGL Pipeline System | Texas | 100.0% | 2,016 | Texas | 100.0% | 1,957 |
Dixie Pipeline (1) | South and Southeastern U.S. | 100.0% | 1,307 | 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% | 1,229 | Texas to Midwest and Northeast U.S. | 100.0% | 1,224 |
Chaparral NGL System (1) | Texas, New Mexico | 100.0% | 1,085 | |||
Chaparral NGL System | Texas, New Mexico | 100.0% | 1,080 | |||
Louisiana Pipeline System (1) | Louisiana | 100.0% | 877 | Louisiana | 100.0% | 874 |
Seminole NGL Pipeline (1) | Texas | 100.0% | 869 | |||
Shin Oak NGL Pipeline | Texas | 67.0% (3) | 669 | Texas | 67.0% (3) | 668 |
Texas Express Pipeline (1) | Texas | 35.0% (4) | 594 | Texas | 35.0% (4) | 593 |
Skelly-Belvieu Pipeline (1) | Texas, Oklahoma | 50.0% (5) | 572 | Texas, Oklahoma | 50.0% (5) | 572 |
Front Range Pipeline (1) | Colorado, Oklahoma, Texas | 33.3% (6) | 451 | Colorado, Oklahoma, Texas | 33.3% (6) | 452 |
Houston Ship Channel Pipeline System | Texas | 100.0% | 306 | Texas | 100.0% | 304 |
Aegis Ethane Pipeline (1) | Texas, Louisiana | 100.0% | 299 | |||
Panola Pipeline (1) | Texas | 55.0% (7) | 253 | Texas | 55.0% (7) | 253 |
Rio Grande Pipeline (1) | Texas | 100.0% | 249 | Texas | 100.0% | 248 |
Aegis Ethane Pipeline (1) | Texas, Louisiana | 100.0% | 232 | |||
Lou-Tex NGL Pipeline (1) | Texas, Louisiana | 100.0% | 206 | Texas, Louisiana | 100.0% | 209 |
Promix NGL Gathering System | Louisiana | 50.0% (8) | 194 | Louisiana | 50.0% (8) | 191 |
Tri-States NGL Pipeline (1) | Alabama, Mississippi, Louisiana | 83.3% (9) | 168 | Alabama, Mississippi, Louisiana | 83.3% (9) | 168 |
Texas Express Gathering System | Texas | 45.0% (10) | 138 | Texas | 45.0% (10) | 138 |
Others (eight systems) (2) | Various | Various (11) | 459 | |||
Others (nine systems) (2) | Various | Various (11) | 523 | |||
Total | 19,803 | 20,081 |
(1) | Interstate transportation services provided |
(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 |
(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, |
(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 |
• | The Mid-America Pipeline System is an NGL pipeline system consisting of the |
• | 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 |
• | 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 | Net Plant | Total Plant | |||||
Ownership | Capacity | Capacity | Ownership | Capacity | Capacity | |||
Description of Asset | Location | Interest | (MBPD) (1) | (MBPD) | Location | Interest | (MBPD) (1) | (MBPD) (2) |
NGL fractionation facilities: | ||||||||
Chambers County: | ||||||||
Fracs I, II and III | Texas | 75.0% (2) | 189 | 245 | ||||
Fracs IV, V, VI ,IX, X and XI | Texas | 100.0% | 645 | 645 | ||||
Fracs VII and VIII | Texas | 75.0% (3) | 128 | 170 | ||||
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 | 962 | 1,060 | 1,087 | 1,185 | ||||
Shoup and Armstrong | Texas | 100.0% | 93 | 93 | Texas | 100.0% | 97 | 97 |
Hobbs | Texas | 100.0% | 75 | 75 | Texas | 100.0% | 75 | 75 |
Norco | Louisiana | 100.0% | 75 | 75 | Louisiana | 100.0% | 75 | 75 |
Promix | Louisiana | 50.0% (4) | 73 | 145 | Louisiana | 50.0% (5) | 73 | 145 |
Tebone | Louisiana | 100.0% | 30 | 30 | Louisiana | 100.0% | 30 | 30 |
Baton Rouge | Louisiana | 32.2% (5) | 19 | 60 | Louisiana | 32.2% (6) | 19 | 60 |
Total | 1,327 | 1,538 | 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. |
We own a 75% consolidated equity interest in NGL fractionators | |
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. | |
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 | Net Usable | |||||
Storage | Storage | |||||
Ownership | Capacity | Ownership | Capacity | |||
Description of Asset | Location | Interest | (MMBbls) (1) | Location | Interest | (MMBbls) (1) |
Chambers County storage complex | Texas | 100.0% | 129.8 | Texas | 100.0% | 169.5 |
Almeda and Markham (2) | Texas | Leased | 12.4 | Texas | Leased | 12.4 |
Breaux Bridge, Anse La Butte and Sorrento (3) | Louisiana | 100.0% | 11.0 | Louisiana | 100.0% | 11.0 |
Petal (4) | Mississippi | 100.0% | 5.4 | Mississippi | 100.0% | 5.4 |
Hutchinson (5) | Kansas | 100.0% | 4.0 | Kansas | 100.0% | 4.0 |
Others (6) | Various | 14.4 | Various | 14.4 | ||
Total | 177.0 | 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 |
• | 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 |
Operational | Operational | |||||||
Our | Storage | Pipeline | Storage | Pipeline | ||||
Ownership | Capacity | Length | Ownership | Capacity | Length | |||
Description of Asset | Location(s) | Interest | (MMBbls) (2) | (Miles) | Location(s) | Interest | (MMBbls) (2) | (Miles) |
Midland-to-ECHO System: | ||||||||
Midland-to-ECHO 1 pipeline | Texas | 80.0% (3) | 3.7 | 418 | ||||
Midland-to-ECHO 2 pipeline | Texas | 100.0% | – | 444 | ||||
Midland-to-ECHO 3 pipeline | Texas | 29.0% (4) | – | 521 | ||||
Total Midland-to-ECHO System: | 3.7 | 1,383 | ||||||
Seaway Pipeline (1) | Texas, Oklahoma | 50.0% (5) | 9.8 | 1,273 | Texas, Oklahoma | 50.0% (3) | 9.7 | 1,273 |
West Texas System (1) | Texas, New Mexico | 100.0% | 1.3 | 1,030 | 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% (6) | 6.0 | 601 | Texas, New Mexico, Oklahoma | 13.0% (5) | 5.2 | 601 |
South Texas Crude Oil Pipeline System | Texas | 100.0% | 5.6 | 560 | Texas | 100.0% | 5.6 | 508 |
EFS Midstream System | Texas | 100.0% | 0.3 | 500 | Texas | 100.0% | 0.3 | 500 |
Eagle Ford Crude Oil Pipeline System | Texas | 50.0% (7) | 4.5 | 390 | Texas | 50.0% (6) | 4.5 | 390 |
Total | 31.2 | 5,737 | 30.7 | 5,291 |
(1) | Transportation services provided |
(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”). | |
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. |
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 | Number of | Net Storage | |||||
Ownership | Above-Ground | Capacity | Ownership | Above-Ground | Capacity | |||
Description of Asset | Location(s) | Interest | Tanks in Service | (MMBbls) | Location | Interest | Tanks in Service | (MMBbls) |
EHT (crude oil) | Texas | 100.0% | 82 | 23.6 | Texas | 100.0% | 81 | 24.0 |
ECHO (1) | Texas | 100.0% | 15 | 6.5 | Texas | 100.0% | 15 | 6.6 |
Midland (2) | Texas | 100.0% | 13 | 5.2 | Texas | 100.0% | 13 | 5.2 |
Beaumont Marine West | Texas | 100.0% | 12 | 4.2 | Texas | 100.0% | 12 | 4.2 |
Cushing | Oklahoma | 100.0% | 19 | 3.3 | Oklahoma | 100.0% | 19 | 3.5 |
Corpus Christi | Texas | 50.0% (3) | 4 | 0.7 | Texas | 50.0% (3) | 4 | 0.7 |
Total | 145 | 43.5 | 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 |
• | 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 |
• | 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) | Net Capacity (1) | |||||||||||
Pipeline | Pipeline | Natural Gas | Usable | Pipeline | Pipeline | Natural Gas | Usable | |||||
Ownership | Length | Capacity | Treating | Storage | Ownership | Length | Capacity | Treating | Storage | |||
Description of Asset | Location(s) | Interest | (Miles) | (MMcf/d) | (MMcf/d) | (Bcf) | Location(s) | Interest | (Miles) | (MMcf/d) | (MMcf/d) | (Bcf) |
Texas Intrastate System (2) | Texas | Various (5) | 6,812 | 7,328 | – | 12.9 | Texas | Various (5) | 6,719 | 7,328 | – | 12.9 |
Acadian Gas System (2) | Louisiana | 100.0% (6) | 1,390 | 4,400 | – | 1.3 | Louisiana | 100.0% (6) | 1,409 | 4,825 | – | 1.2 |
Jonah Gathering System | Wyoming | 100.0% | 776 | 2,360 | – | – | 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% | 191 | 1,800 | – | – | Colorado | 100.0% | 195 | 1,800 | – | – |
Permian Basin Gathering System | Texas, New Mexico | 100.0% | 1,770 | 1,575 | 150 | – | ||||||
White River Hub (3) | Colorado | 50.0% (7) | 10 | 1,500 | – | – | Colorado | 50.0% (7) | 10 | 1,500 | – | – |
BTA Gathering System (4) | Texas | 100.0% (8) | 798 | 1,420 | 240 | – | Texas | 100.0% (8) | 804 | 1,420 | 240 | – |
Haynesville Gathering System | Louisiana, Texas | 100.0% | 378 | 1,300 | 810 | – | Louisiana, Texas | 100.0% | 364 | 1,300 | 810 | – |
San Juan Gathering System | New Mexico, Colorado | 100.0% | 5,599 | 1,200 | – | – | New Mexico, Colorado | 100.0% | 5,568 | 1,200 | – | – |
Indian Springs Gathering System (4) | Texas | 80.0% (9) | 145 | 160 | – | – | Texas | 80.0% (9) | 145 | 160 | – | – |
Delmita Gathering System | Texas | 100.0% | 203 | 145 | – | – | Texas | 100.0% | 201 | 145 | – | – |
South Texas Gathering System | Texas | 100.0% | 517 | 143 | 320 | – | Texas | 100.0% | 524 | 143 | 320 | – |
Old Ocean Pipeline | Texas | 50.0% (10) | 240 | 80 | – | – | Texas | 50.0% (10) | 240 | 80 | – | – |
Big Thicket Gathering System (4) | Texas | 100.0% | 250 | 60 | – | – | Texas | 100.0% | 234 | 60 | – | – |
Central Treating Facility | Colorado | 100.0% | – | 200 | – | Colorado | 100.0% | – | 200 | – | ||
Total | 19,079 | 23,471 | 1,720 | 14.2 | 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 |
(3) | Services provided by the White River Hub are regulated by federal governmental agencies. |
(4) | Transportation services provided |
(5) | We proportionately consolidate our undivided interests, which range from 22% to 80%, in |
(6) | The Acadian Gas System includes a leased |
(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 |
(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 |
• | The Acadian Gas System transports, stores and markets natural gas in Louisiana. The Acadian Gas System is comprised of the |
• | 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 |
• | The Delaware Basin Gathering System is comprised of the |
• | 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 |
• | 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 |
• | 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/ |
• | 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 |
• | 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. |
Our | Net Plant | Total Plant | Net Plant | Total Plant | ||||
Ownership | Capacity | Capacity | Ownership | Capacity | Capacity | |||
Description of Asset | Location | Interest | (MBPD) | (MBPD) | Location | Interest | (MBPD) | (MBPD) |
Propylene fractionation facilities: | ||||||||
Chambers County (six units) | Texas | Various (1) | 80 | 93 | Texas | Various (1) | 82 | 95 |
BRPC (one unit) | Louisiana | 30.0% (2) | 7 | 23 | Louisiana | 30.0% (2) | 7 | 23 |
Total | 87 | 116 | 89 | 118 | ||||
PDH facility: | ||||||||
PDH facilities: | ||||||||
PDH 1 | Texas | 100.0% | 25 | 25 | 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 |
(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 | Ownership | Length | |||
Description of Asset | Location(s) | Interest | (Miles) | Location(s) | Interest | (Miles) |
Texas RGP Gathering System | Texas | 100.0% | 708 | |||
Lou-Tex Propylene Pipeline | Texas, Louisiana | 100.0% | 267 | Texas, Louisiana | 100.0% | 267 |
North Dean Pipeline System | Texas | 100.0% | 192 | Texas | 100.0% | 254 |
Texas City RGP Gathering System | Texas | 100.0% | 157 | |||
Propylene Splitter PGP Distribution System | Texas | 100.0% | 120 | Texas | 100.0% | 152 |
Taurus Pipeline | Texas | 70.0% (1) | 115 | Texas | 70.0% (1) | 115 |
Louisiana RGP Gathering System | Louisiana | 100.0% | 63 | Louisiana | 100.0% | 63 |
Lake Charles PGP Pipeline | Texas, Louisiana | 50.0% (2) | 27 | Texas, Louisiana | 50.0% (2) | 27 |
Sabine Pipeline | Texas, Louisiana | 100.0% | 24 | Texas, Louisiana | 100.0% | 24 |
La Porte PGP Pipeline | Texas | 80.0% (3) | 20 | Texas | 80.0% (3) | 20 |
Total | 985 | 1,630 |
(1) | We own a 70% consolidated interest in the Taurus |
(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, | For the Year Ended December 31, | |||||||||||||||||||||||
2021 | 2020 | 2019 | 2023 | 2022 | 2021 | |||||||||||||||||||
Refined products transportation (MBPD) | 464 | 419 | 407 | 502 | 447 | 464 | ||||||||||||||||||
Petrochemical transportation (MBPD) | 170 | 156 | 126 | – | – | 170 | ||||||||||||||||||
NGL transportation (MBPD) | 52 | 55 | 63 | 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 2021 | – | $ | – | – | $ | 1,644,128 | ||||||||||
November 2021 | 1,784,058 | $ | 22.13 | 1,784,058 | $ | 1,604,655 | ||||||||||
December 2021 | 4,030,705 | $ | 21.22 | 4,030,705 | $ | 1,519,128 | ||||||||||
Vesting of phantom unit awards: | ||||||||||||||||
November 2021 (2) | 9,193 | $ | 22.75 | n/a | n/a |
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) | Of the |
/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 | Polymer | Refinery | Indicative Gas | |||||||||||||
Natural | Normal | Natural | Grade | Grade | Processing | Natural | Normal | Natural | Grade | Grade | Processing | |||||||
Gas, | Ethane, | Propane, | Butane, | Isobutane, | Gasoline, | Propylene, | Propylene, | Gross Spread | Gas, | Ethane, | Propane, | Butane, | Isobutane, | Gasoline, | Propylene, | Propylene, | Gross Spread | |
$/MMBtu | $/gallon | $/gallon | $/gallon | $/gallon | $/pound | $/pound | $/gallon | $/MMBtu | $/gallon | $/gallon | $/gallon | $/gallon | $/pound | $/pound | $/gallon | |||
(1) | (2) | (2) | (2) | (2) | (3) | (3) | (4) | (1) | (2) | (2) | (2) | (2) | (3) | (3) | (4) | |||
2020 by quarter: | ||||||||||||||||||
2022 by quarter: | ||||||||||||||||||
1st Quarter | $1.95 | $0.14 | $0.37 | $0.57 | $0.63 | $0.93 | $0.31 | $0.18 | $0.19 | $4.96 | $0.40 | $1.30 | $1.59 | $1.60 | $2.21 | $0.63 | $0.39 | $0.55 |
2nd Quarter | $1.71 | $0.19 | $0.41 | $0.43 | $0.44 | $0.41 | $0.26 | $0.11 | $0.17 | $7.17 | $0.59 | $1.24 | $1.50 | $1.68 | $2.17 | $0.61 | $0.40 | $0.46 |
3rd Quarter | $1.98 | $0.22 | $0.50 | $0.58 | $0.60 | $0.80 | $0.35 | $0.17 | $0.25 | $8.20 | $0.55 | $1.08 | $1.19 | $1.44 | $1.72 | $0.47 | $0.28 | $0.26 |
4th Quarter | $2.67 | $0.21 | $0.57 | $0.76 | $0.68 | $0.92 | $0.41 | $0.24 | $0.22 | $6.26 | $0.39 | $0.79 | $0.97 | $1.03 | $1.54 | $0.32 | $0.18 | $0.17 |
2020 Averages | $2.08 | $0.19 | $0.46 | $0.59 | $0.77 | $0.33 | $0.18 | $0.21 | ||||||||||
2022 Averages | $6.65 | $0.48 | $1.10 | $1.31 | $1.44 | $1.91 | $0.51 | $0.31 | $0.36 | |||||||||
2021 by quarter: | ||||||||||||||||||
2023 by quarter: | ||||||||||||||||||
1st Quarter | $2.71 | $0.24 | $0.89 | $0.94 | $0.93 | $1.33 | $0.73 | $0.44 | $0.38 | $3.44 | $0.25 | $0.82 | $1.11 | $1.16 | $1.62 | $0.50 | $0.22 | $0.37 |
2nd Quarter | $2.83 | $0.26 | $0.87 | $0.97 | $0.98 | $1.46 | $0.67 | $0.27 | $0.41 | $2.09 | $0.21 | $0.67 | $0.78 | $0.84 | $1.44 | $0.40 | $0.21 | $0.37 |
3rd Quarter | $4.02 | $0.35 | $1.16 | $1.34 | $1.62 | $0.82 | $0.36 | $0.51 | $2.54 | $0.30 | $0.68 | $0.83 | $0.94 | $1.55 | $0.36 | $0.15 | $0.40 | |
4th Quarter | $5.84 | $0.39 | $1.24 | $1.46 | $1.82 | $0.66 | $0.33 | $0.41 | $2.88 | $0.23 | $0.67 | $0.91 | $1.07 | $1.48 | $0.46 | $0.17 | $0.33 | |
2021 Averages | $3.85 | $0.31 | $1.04 | $1.18 | $1.56 | $0.72 | $0.35 | $0.43 | ||||||||||
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 |
(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 | WTI | Midland | Houston | LLS | |
Crude Oil, | Crude Oil | Crude Oil, | Crude Oil, | Crude Oil | Crude Oil, | |||
$/barrel | $/barrel | |||||||
(1) | (2) | (3) | (1) | (2) | (3) | |||
2020 by quarter: | ||||||||
2022 by quarter: | ||||||||
1st Quarter | $46.17 | $45.51 | $47.81 | $48.15 | $94.29 | $96.43 | $96.77 | |
2nd Quarter | $27.85 | $28.22 | $29.68 | $30.12 | $108.41 | $109.66 | $109.96 | $110.17 |
3rd Quarter | $40.93 | $41.05 | $41.77 | $42.47 | $91.56 | $93.41 | $93.77 | $94.17 |
4th Quarter | $42.66 | $43.07 | $43.63 | $44.08 | $82.64 | $83.97 | $84.33 | $85.50 |
2020 Averages | $39.40 | $39.46 | $40.72 | $41.21 | ||||
2022 Averages | $94.23 | $95.87 | $96.21 | $96.65 | ||||
2021 by quarter: | ||||||||
2023 by quarter: | ||||||||
1st Quarter | $57.84 | $59.00 | $59.51 | $59.99 | $76.13 | $77.50 | $77.74 | $79.00 |
2nd Quarter | $66.07 | $66.41 | $66.90 | $67.95 | $73.78 | $74.48 | $74.68 | $75.87 |
3rd Quarter | $70.56 | $70.74 | $71.17 | $71.51 | $82.26 | $83.85 | $84.02 | $84.72 |
4th Quarter | $77.19 | $77.82 | $78.27 | $78.41 | $78.32 | $79.62 | $79.89 | $80.93 |
2021 Averages | $67.92 | $68.49 | $68.96 | $69.47 | ||||
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, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Revenues | $ | 40,806.9 | $ | 27,199.7 | $ | 49,715 | $ | 58,186 | ||||||||
Costs and expenses: | ||||||||||||||||
Operating costs and expenses: | ||||||||||||||||
Cost of sales | 29,887.0 | 16,723.2 | 37,023 | 45,836 | ||||||||||||
Other operating costs and expenses | 2,914.1 | 2,800.2 | 3,695 | 3,454 | ||||||||||||
Depreciation, amortization and accretion expenses | 2,037.5 | 1,961.5 | 2,279 | 2,158 | ||||||||||||
Asset impairment charges | 232.6 | 890.6 | 30 | 53 | ||||||||||||
Net gains attributable to asset sales and related matters | 6.1 | (4.4 | ) | |||||||||||||
Net losses (gains) attributable to asset sales and related matters | (10 | ) | 1 | |||||||||||||
Total operating costs and expenses | 35,077.3 | 22,371.1 | 43,017 | 51,502 | ||||||||||||
General and administrative costs | 209.3 | 219.6 | 231 | 241 | ||||||||||||
Total costs and expenses | 35,286.6 | 22,590.7 | 43,248 | 51,743 | ||||||||||||
Equity in income of unconsolidated affiliates | 583.4 | 426.1 | 462 | 464 | ||||||||||||
Operating income | 6,103.7 | 5,035.1 | 6,929 | 6,907 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest expense | (1,283.0 | ) | (1,287.4 | ) | (1,269 | ) | (1,244 | ) | ||||||||
Other, net | 4.6 | 13.7 | 41 | 34 | ||||||||||||
Total other expense, net | (1,278.4 | ) | (1,273.7 | ) | (1,228 | ) | (1,210 | ) | ||||||||
Income before income taxes | 4,825.3 | 3,761.4 | 5,701 | 5,697 | ||||||||||||
Benefit from (provision for) income taxes | (70.0 | ) | 124.3 | |||||||||||||
Provision for income taxes | (44 | ) | (82 | ) | ||||||||||||
Net income | 4,755.3 | 3,885.7 | 5,657 | 5,615 | ||||||||||||
Net income attributable to noncontrolling interests | (117.6 | ) | (110.1 | ) | (125 | ) | (125 | ) | ||||||||
Net income attributable to preferred units | (3.6 | ) | (0.9 | ) | (3 | ) | (3 | ) | ||||||||
Net income attributable to common unitholders | $ | 4,634.1 | $ | 3,774.7 | $ | 5,529 | $ | 5,487 |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
NGL Pipelines & Services: | ||||||||||||||||
Sales of NGLs and related products | $ | 13,716.5 | $ | 8,970.7 | $ | 14,846 | $ | 21,307 | ||||||||
Midstream services | 2,586.1 | 2,206.5 | 2,799 | 2,952 | ||||||||||||
Total | 16,302.6 | 11,177.2 | 17,645 | 24,259 | ||||||||||||
Crude Oil Pipelines & Services: | ||||||||||||||||
Sales of crude oil | 9,519.0 | 5,410.8 | 18,185 | 17,301 | ||||||||||||
Midstream services | 1,383.2 | 1,278.2 | 1,151 | 1,260 | ||||||||||||
Total | 10,902.2 | 6,689.0 | 19,336 | 18,561 | ||||||||||||
Natural Gas Pipelines & Services: | ||||||||||||||||
Sales of natural gas | 3,412.7 | 1,530.5 | 2,373 | 5,019 | ||||||||||||
Midstream services | 986.9 | 1,022.6 | 1,403 | 1,241 | ||||||||||||
Total | 4,399.6 | 2,553.1 | 3,776 | 6,260 | ||||||||||||
Petrochemical & Refined Products Services: | ||||||||||||||||
Sales of petrochemicals and refined products | 8,195.7 | 5,942.6 | 7,689 | 8,003 | ||||||||||||
Midstream services | 1,006.8 | 837.8 | 1,269 | 1,103 | ||||||||||||
Total | 9,202.5 | 6,780.4 | 8,958 | 9,106 | ||||||||||||
Total consolidated revenues | $ | 40,806.9 | $ | 27,199.7 | $ | 49,715 | $ | 58,186 |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Interest charged on debt principal outstanding | $ | 1,298.9 | $ | 1,330.6 | $ | 1,355 | $ | 1,288 | ||||||||
Impact of interest rate hedging program, including related amortization | 38.3 | 39.3 | (5 | ) | 19 | |||||||||||
Interest costs capitalized in connection with construction projects | (79.6 | ) | (115.0 | ) | (106 | ) | (90 | ) | ||||||||
Other | 25.4 | 32.5 | 25 | 27 | ||||||||||||
Total | $ | 1,283.0 | $ | 1,287.4 | $ | 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. |
For the Year Ended December 31, | ||||||||
2021 | 2020 | |||||||
Deferred tax benefit (expense) attributable to OTA | $ | (27.6 | ) | $ | 155.3 | |||
Revised Texas Franchise Tax (“Texas Margin Tax”) | (41.9 | ) | (32.1 | ) | ||||
Other | (0.5 | ) | 1.1 | |||||
Benefit from (provision for) income taxes | $ | (70.0 | ) | $ | 124.3 |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Gross operating margin by segment: | ||||||||||||||||
NGL Pipelines & Services | $ | 4,315.9 | $ | 4,182.4 | $ | 4,898 | $ | 5,142 | ||||||||
Crude Oil Pipelines & Services | 1,679.9 | 1,997.3 | 1,707 | 1,655 | ||||||||||||
Natural Gas Pipelines & Services | 1,155.5 | 926.6 | 1,077 | 1,042 | ||||||||||||
Petrochemical & Refined Products Services | 1,357.2 | 1,081.8 | 1,694 | 1,517 | ||||||||||||
Total segment gross operating margin (1) | 8,508.5 | 8,188.1 | 9,376 | 9,356 | ||||||||||||
Net adjustment for shipper make-up rights | 53.8 | (85.7 | ) | 19 | (47 | ) | ||||||||||
Total gross operating margin (non-GAAP) | $ | 8,562.3 | $ | 8,102.4 | $ | 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, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Operating income | $ | 6,103.7 | $ | 5,035.1 | $ | 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) | 2,010.6 | 1,961.5 | 2,215 | 2,107 | ||||||||||||
Asset impairment charges in operating costs and expenses | 232.6 | 890.6 | 30 | 53 | ||||||||||||
Net losses (gains) attributable to asset sales and related matters in operating costs and expenses | 6.1 | (4.4 | ) | (10 | ) | 1 | ||||||||||
General and administrative costs | 209.3 | 219.6 | 231 | 241 | ||||||||||||
Total gross operating margin (non-GAAP) | $ | 8,562.3 | $ | 8,102.4 | $ | 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, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Segment gross operating margin: | ||||||||||||||||
Natural gas processing and related NGL marketing activities | $ | 1,134.8 | $ | 997.5 | $ | 1,300 | $ | 1,946 | ||||||||
NGL pipelines, storage and terminals | 2,323.7 | 2,524.1 | 2,771 | 2,362 | ||||||||||||
NGL fractionation | 857.4 | 660.8 | 827 | 834 | ||||||||||||
Total | $ | 4,315.9 | $ | 4,182.4 | $ | 4,898 | $ | 5,142 | ||||||||
Selected volumetric data: | ||||||||||||||||
NGL pipeline transportation volumes (MBPD) | 3,412 | 3,589 | 4,040 | 3,703 | ||||||||||||
NGL marine terminal volumes (MBPD) | 658 | 722 | 821 | 723 | ||||||||||||
NGL fractionation volumes (MBPD) | 1,253 | 1,359 | 1,556 | 1,339 | ||||||||||||
Equity NGL production volumes (MBPD) (1) | 167 | 151 | ||||||||||||||
Equity NGL-equivalent production volumes (MBPD) (1) | 175 | 182 | ||||||||||||||
Fee-based natural gas processing volumes (MMcf/d) (2, 3) | 4,057 | 4,285 | 5,848 | 5,182 |
(1) | |
(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, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Segment gross operating margin: | ||||||||||||||||
Midland-to-ECHO System and related business activities | $ | 381.4 | $ | 359.2 | $ | 551 | $ | 393 | ||||||||
Other crude oil pipelines, terminals and related marketing results | 1,298.5 | 1,638.1 | 1,156 | 1,262 | ||||||||||||
Total | $ | 1,679.9 | $ | 1,997.3 | $ | 1,707 | $ | 1,655 | ||||||||
Selected volumetric data: | ||||||||||||||||
Crude oil pipeline transportation volumes (MBPD) | 2,088 | 2,166 | 2,461 | 2,222 | ||||||||||||
Crude oil marine terminal volumes (MBPD) | 645 | 724 | 913 | 788 |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Segment gross operating margin | $ | 1,155.5 | $ | 926.6 | $ | 1,077 | $ | 1,042 | ||||||||
Selected volumetric data: | ||||||||||||||||
Natural gas pipeline transportation volumes (BBtus/d) | 14,249 | 13,421 | 18,365 | 17,107 |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Segment gross operating margin: | ||||||||||||||||
Propylene production and related activities | $ | 798.2 | $ | 471.0 | $ | 583 | $ | 564 | ||||||||
Butane isomerization and related operations | 75.0 | 67.6 | 124 | 114 | ||||||||||||
Octane enhancement and related plant operations | 106.9 | 161.7 | 442 | 394 | ||||||||||||
Refined products pipelines and related activities | 289.6 | 318.6 | 357 | 277 | ||||||||||||
Ethylene exports and related activities | 73.8 | 25.6 | 123 | 123 | ||||||||||||
Marine transportation and other services | 13.7 | 37.3 | 65 | 45 | ||||||||||||
Total | $ | 1,357.2 | $ | 1,081.8 | $ | 1,694 | $ | 1,517 | ||||||||
Selected volumetric data: | ||||||||||||||||
Propylene production volumes (MBPD) | 99 | 89 | 101 | 101 | ||||||||||||
Butane isomerization volumes (MBPD) | 85 | 96 | 112 | 108 | ||||||||||||
Standalone DIB processing volumes (MBPD) | 154 | 127 | 176 | 159 | ||||||||||||
Octane enhancement and related plant sales volumes (MBPD) (1) | 33 | 35 | 36 | 39 | ||||||||||||
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) | 890 | 802 | 836 | 747 | ||||||||||||
Marine terminal volumes, primarily refined products and petrochemicals (MBPD) | 234 | 262 | 320 | 202 |
(1) | Reflects aggregate sales volumes for our octane |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Net cash flows provided by operating activities | $ | 8,512.5 | $ | 5,891.5 | $ | 7,569 | $ | 8,039 | ||||||||
Cash used in investing activities | 2,134.6 | 3,120.7 | 3,197 | 4,954 | ||||||||||||
Cash used in financing activities | 4,571.3 | 2,022.7 | 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 |
• | a $1.3 billion year-to-year |
• | 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, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Net income attributable to common unitholders (GAAP) (1) | $ | 4,634.1 | $ | 3,774.7 | $ | 5,529 | $ | 5,487 | ||||||||
Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): | ||||||||||||||||
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 | 2,139.8 | 2,071.9 | 2,343 | 2,245 | ||||||||||||
Cash distributions received from unconsolidated affiliates (2) | 590.1 | 614.1 | 488 | 544 | ||||||||||||
Equity in income of unconsolidated affiliates | (583.4 | ) | (426.1 | ) | (462 | ) | (464 | ) | ||||||||
Asset impairment charges | 232.8 | 890.6 | 32 | 53 | ||||||||||||
Change in fair market value of derivative instruments | (27.4 | ) | (79.3 | ) | 33 | 78 | ||||||||||
Deferred income tax expense (benefit) | 39.8 | (147.6 | ) | |||||||||||||
Deferred income tax expense | 12 | 60 | ||||||||||||||
Sustaining capital expenditures (3) | (430.1 | ) | (293.6 | ) | (413 | ) | (372 | ) | ||||||||
Other, net | (126.8 | ) | 22.5 | (24 | ) | (2 | ) | |||||||||
Operational DCF (5) | $ | 6,468.9 | $ | 6,427.2 | ||||||||||||
Proceeds from asset sales | 64.3 | 12.8 | ||||||||||||||
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 | 75.2 | (33.3 | ) | 21 | – | |||||||||||
DCF (non-GAAP) | $ | 6,608.4 | $ | 6,406.7 | $ | 7,601 | $ | 7,751 | ||||||||
Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards | $ | 3,992.6 | $ | 3,926.8 | $ | 4,393 | $ | 4,182 | ||||||||
Cash distribution per common unit declared by Enterprise GP with respect to period | $ | 1.8150 | $ | 1.7850 | $ | 2.0050 | $ | 1.9050 | ||||||||
Total DCF retained by the Partnership with respect to period | $ | 2,615.8 | $ | 2,479.9 | $ | 3,208 | $ | 3,569 | ||||||||
Distribution coverage ratio | 1.66 | x | 1.63 | x | 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. | |
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. | |
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, | ||||||||
2021 | 2020 | |||||||
Net cash flows provided by operating activities (GAAP) | $ | 8,512.5 | $ | 5,891.5 | ||||
Adjustments to reconcile net cash flows provided by operating activities to DCF (addition or subtraction indicated by sign): | ||||||||
Net effect of changes in operating accounts | (1,366.7 | ) | 767.5 | |||||
Sustaining capital expenditures | (430.1 | ) | (293.6 | ) | ||||
Distributions received from unconsolidated affiliates attributable to the return of capital | 46.3 | 187.5 | ||||||
Proceeds from asset sales | 64.3 | 12.8 | ||||||
Net income attributable to noncontrolling interests | (117.6 | ) | (110.1 | ) | ||||
Monetization of interest rate derivative instruments accounted for as cash flow hedges | 75.2 | (33.3 | ) | |||||
Other, net | (175.5 | ) | (15.6 | ) | ||||
DCF (non-GAAP) | $ | 6,608.4 | $ | 6,406.7 |
For the Year Ended December 31, | ||||||||
2021 | 2020 | |||||||
Net cash flows provided by operating activities (GAAP) | $ | 8,512.5 | $ | 5,891.5 | ||||
Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign): | ||||||||
Cash used in investing activities | (2,134.6 | ) | (3,120.7 | ) | ||||
Cash contributions from noncontrolling interests | 72.4 | 30.9 | ||||||
Cash distributions paid to noncontrolling interests | (153.7 | ) | (131.3 | ) | ||||
FCF (non-GAAP) | $ | 6,296.6 | $ | 2,670.4 |
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, | For the Year Ended December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Capital investments for property, plant and equipment: (1) | ||||||||||||||||
Growth capital projects (2) | $ | 1,807.4 | $ | 2,985.8 | $ | 2,844 | $ | 1,606 | ||||||||
Sustaining capital projects (3) | 415.8 | 302.1 | 422 | 358 | ||||||||||||
Total | $ | 2,223.2 | $ | 3,287.9 | $ | 3,266 | $ | 1,964 | ||||||||
Cash used for business combinations, net (4) | $ | – | $ | 3,204 | ||||||||||||
Investments in unconsolidated affiliates | $ | 2.1 | $ | 15.6 | $ | 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 | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | Total | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | |||||||||||||||||||||||||||||||||||||||||||
Principal amount of senior and junior debt obligations | $ | 29,821.4 | $ | 1,400.0 | $ | 1,250.0 | $ | 850.0 | $ | 1,150.0 | $ | 875.0 | $ | 24,296.4 | ||||||||||||||||||||||||||||||||||||||||||
Principal amount of debt obligations | $ | 29,021 | $ | 1,300 | $ | 1,150 | $ | 1,625 | $ | 575 | $ | 1,000 | $ | 23,371 | ||||||||||||||||||||||||||||||||||||||||||
Estimated cash payments for interest (1) | 28,488.2 | 1,272.4 | 1,232.2 | 1,194.0 | 1,152.6 | 1,118.4 | 22,518.6 | $ | 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, |
Total | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | ||||||||||||||||||||||
Product purchase commitments | $ | 18,805.1 | $ | 3,420.7 | $ | 3,070.9 | $ | 2,807.7 | $ | 2,348.6 | $ | 1,988.6 | $ | 5,168.6 |
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 | $ | 358.4 | $ | 2,569 | ||||
Other current assets | 7,993.7 | 5,416 | ||||||
Long-term receivables from Non-Obligor Subsidiaries | 187.3 | 187 | ||||||
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $45.92 billion | 8,790.8 | |||||||
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 $452.7 million | $ | 1,852.5 | ||||||
Current portion of Guaranteed Debt, including interest of $455 million | $ | 1,755 | ||||||
Current payables to Non-Obligor Subsidiaries | 1,829.1 | 1,567 | ||||||
Other current liabilities | 4,743.2 | 4,239 | ||||||
Noncurrent portion of Guaranteed Debt, principal only | 28,406.8 | 27,707 | ||||||
Noncurrent payables to Non-Obligor Subsidiaries | 27.0 | 57 | ||||||
Other noncurrent liabilities | 48.7 | 122 | ||||||
Mezzanine equity of Obligor Group: | ||||||||
Preferred units | $ | 49.3 | $ | 49 |
Revenues from Non-Obligor Subsidiaries | $ | 13,113.8 | $ | 17,344 | ||||
Revenues from other sources | 16,676.5 | 15,375 | ||||||
Operating income of Obligor Group | 1,489.8 | 835 | ||||||
Net income of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $4.49 billion | 144.9 | |||||||
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 | Portfolio Fair Value at | |||||||||||||||||||||||||
Scenario | Resulting Classification | December 31, 2020 | December 31, 2021 | January 31, 2022 | Resulting Classification | December 31, 2022 | December 31, 2023 | January 31, 2024 | ||||||||||||||||||
Fair value assuming no change in underlying commodity prices | Asset (Liability) | $ | 3.7 | $ | 8.8 | $ | (8.3 | ) | Asset (Liability) | $ | 90 | $ | 7 | $ | 10 | |||||||||||
Fair value assuming 10% increase in underlying commodity prices | Asset (Liability) | 2.6 | 8.9 | (10.1 | ) | Asset (Liability) | 97 | 6 | 9 | |||||||||||||||||
Fair value assuming 10% decrease in underlying commodity prices | Asset (Liability) | 4.9 | 8.7 | (6.5 | ) | Asset (Liability) | 83 | 8 | 11 |
Portfolio Fair Value at | Portfolio Fair Value at | |||||||||||||||||||||||||
Scenario | Resulting Classification | December 31, 2020 | December 31, 2021 | January 31, 2022 | Resulting Classification | December 31, 2022 | December 31, 2023 | January 31, 2024 | ||||||||||||||||||
Fair value assuming no change in underlying commodity prices | Asset (Liability) | $ | (388.2 | ) | $ | 83.9 | $ | 66.3 | Asset (Liability) | $ | 18 | $ | 39 | $ | (31 | ) | ||||||||||
Fair value assuming 10% increase in underlying commodity prices | Asset (Liability) | (521.0 | ) | 76.7 | 65.0 | Asset (Liability) | (29 | ) | 9 | (64 | ) | |||||||||||||||
Fair value assuming 10% decrease in underlying commodity prices | Asset (Liability) | (255.4 | ) | 91.1 | 67.6 | Asset (Liability) | 64 | 69 | 2 |
Portfolio Fair Value at | Portfolio Fair Value at | |||||||||||||||||||||||||
Scenario | Resulting Classification | December 31, 2020 | December 31, 2021 | January 31, 2022 | Resulting Classification | December 31, 2022 | December 31, 2023 | January 31, 2024 | ||||||||||||||||||
Fair value assuming no change in underlying commodity prices | Asset (Liability) | $ | (184.3 | ) | $ | (54.7 | ) | $ | (105.4 | ) | Asset (Liability) | $ | 53 | $ | 66 | $ | 8 | |||||||||
Fair value assuming 10% increase in underlying commodity prices | Asset (Liability) | (266.5 | ) | (120.2 | ) | (164.4 | ) | Asset (Liability) | 24 | (61 | ) | (97 | ) | |||||||||||||
Fair value assuming 10% decrease in underlying commodity prices | Asset (Liability) | (102.1 | ) | 10.9 | (46.4 | ) | 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 | Director and Chairman of the Board | |
Richard H. Bachmann (1,6) | Director and Vice Chairman of the Board | |
A. James Teague (1,6,7,8) | Director and Co-CEO | |
W. Randall Fowler (1,6,7,8) | Director, Co-CEO and CFO | |
Carin M. Barth (2,6) | Director | |
Murray E. Brasseux (4, 6) | 75 | Director |
Rebecca G. Followill (4) | Director | |
James T. Hackett (2,3,6) | Director | |
William C. Montgomery (4,5) | Director | |
John R. Rutherford | ||
Director | ||
Harry P. Weitzel (6,8) | Director and Executive Vice President, General Counsel and Secretary | |
Graham W. Bacon (8) | Executive Vice President and Chief Operating Officer | |
R. Daniel Boss (8) | Executive Vice President – Accounting, Risk Control and Information Technology | |
Christian M. Nelly (8) | Executive Vice President – Finance and Sustainability and Treasurer | |
Brent B. Secrest (8) | 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- | Equity- | |||||||||||
Cash | Based | All Other | Cash | Based | All Other | |||||||
Name and | Salary | Bonus | Awards | Compensation | Total | Salary | Bonus | Awards | Compensation | Total | ||
Principal Position | Year | ($) | ($) (1) | ($) (2) | ($) | Year | ($) | ($) (1) | ($) (2) | ($) | ||
A. James Teague, | 2021 | $ 987,500 | $ 3,200,000 | $ 5,197,500 | $ 1,031,514 | $ 10,416,514 | 2023 | $ 1,149,500 | $ 3,700,000 | $ 7,740,000 | $ 1,377,039 | $ 13,966,539 |
Co-CEO | 2020 | 937,572 | 3,000,000 | 5,796,000 | 915,797 | 10,649,369 | 2022 | 1,075,000 | 3,700,000 | 6,386,500 | 6,192,313 | 17,353,813 |
2019 | 887,500 | 3,000,000 | 5,827,500 | 822,661 | 10,537,661 | 2021 | 987,500 | 3,200,000 | 5,197,500 | 1,031,514 | 10,416,514 | |
W. Randall Fowler, | 2021 | 731,250 | 2,400,000 | 3,898,125 | 753,389 | 7,782,764 | 2023 | 862,125 | 2,775,000 | 5,805,000 | 4,773,863 | 14,215,988 |
Co-CEO and CFO | 2020 | 660,938 | 2,250,000 | 4,399,950 | 637,630 | 7,948,518 | 2022 | 806,250 | 2,775,000 | 4,789,875 | 872,614 | 9,243,739 |
2019 | 609,375 | 2,250,000 | 3,663,000 | 519,072 | 7,041,447 | 2021 | 731,250 | 2,400,000 | 3,898,125 | 753,389 | 7,782,764 | |
Graham W. Bacon, | 2021 | 524,000 | 750,000 | 1,975,050 | 457,633 | 3,706,683 | 2023 | 593,750 | 825,000 | 3,336,500 | 1,617,939 | 6,373,189 |
Executive Vice President and | 2020 | 511,250 | 700,000 | 2,318,400 | 418,486 | 3,948,136 | 2022 | 563,000 | 825,000 | 2,289,500 | 532,326 | 4,209,826 |
Chief Operating Officer | 2019 | 481,250 | 500,000 | 2,358,750 | 386,692 | 3,726,692 | 2021 | 524,000 | 750,000 | 1,975,050 | 457,633 | 3,706,683 |
Brent B. Secrest, | 2021 | 484,000 | 700,000 | 1,975,050 | 397,510 | 3,556,560 | 2023 | 563,750 | 700,000 | 3,185,200 | 1,588,794 | 6,037,744 |
Executive Vice President and | 2020 | 468,750 | 700,000 | 2,356,199 | 315,031 | 3,839,980 | 2022 | 519,250 | 775,000 | 2,289,500 | 490,539 | 4,074,289 |
Chief Commercial Officer | 2019 | 390,000 | 500,000 | 1,248,750 | 219,012 | 2,357,762 | 2021 | 484,000 | 700,000 | 1,975,050 | 397,510 | 3,556,560 |
Christian M. Nelly, | 2021 | 361,969 | 414,375 | 1,662,161 | 260,951 | 2,699,456 | ||||||
Executive Vice President – Finance | 2020 | 336,375 | 390,000 | 1,109,471 | 659,699 | 2,495,545 | ||||||
and Sustainability and Treasurer | ||||||||||||
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 |
(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 | Other | Total All Other Compensation | 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 | $ | 34,800 | $ | 986,400 | $ | 4,697 | $ | 5,617 | $ | 1,031,514 | $ | 39,600 | $ | 1,315,775 | $ | 13,596 | $ | – | $ | 8,068 | $ | 1,377,039 | ||||||||||||||||||||||
W. Randall Fowler | 26,100 | 715,908 | 6,286 | 5,095 | 753,389 | 29,700 | 983,708 | 6,286 | 3,750,000 | 4,169 | 4,773,863 | |||||||||||||||||||||||||||||||||
Graham W. Bacon | 34,800 | 414,285 | 2,838 | 5,710 | 457,633 | 39,600 | 565,873 | 4,356 | 1,000,000 | 8,110 | 1,617,939 | |||||||||||||||||||||||||||||||||
Brent B. Secrest | 31,900 | 359,670 | 990 | 4,950 | 397,510 | 39,600 | 542,476 | 1,518 | 1,000,000 | 5,200 | 1,588,794 | |||||||||||||||||||||||||||||||||
Christian M. Nelly | 31,102 | 223,361 | 965 | 5,523 | 260,951 | |||||||||||||||||||||||||||||||||||||||
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, |
(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 | Grant | |||||||||
Date Fair | Date Fair | |||||||||
Value of | Value of | |||||||||
Estimated Future Payouts Under | Equity- | Estimated Future Payouts Under | Equity- | |||||||
Equity Incentive Plan Awards | Based | Equity Incentive Plan Awards | Based | |||||||
Grant | Threshold | Target | Maximum | Awards | Grant | Threshold | Target | Maximum | Awards | |
Award Type/Named Executive Officer | Date | (#) | (#) | (#) | ($) (1) | Date | (#) | (#) | (#) | ($) (1) |
Phantom unit awards: (2) | ||||||||||
A. James Teague | 2/04/21 | – | 250,000 | – | $ 5,197,500 | 2/09/23 | – | 300,000 | – | $ 7,740,000 |
W. Randall Fowler | 2/04/21 | – | 250,000 | – | 3,898,125 | 2/09/23 | – | 300,000 | – | 5,805,000 |
Graham W. Bacon | 2/04/21 | – | 95,000 | – | 1,975,050 | 2/09/23 | – | 100,000 | – | 2,580,000 |
Brent B. Secrest | 2/04/21 | – | 95,000 | – | 1,975,050 | 2/09/23 | – | 100,000 | – | 2,580,000 |
Christian M. Nelly | 2/04/21 | – | 82,000 | – | 1,662,161 | |||||
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 |
(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 |
(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 | Unit Awards | |||
Number of | Number of | |||
Units | Value | Units | Value | |
Acquired on | Realized on | Acquired on | Realized on | |
Vesting | Vesting | Vesting | Vesting | |
Named Executive Officer | (#) (1) | ($) | (#) (1) | ($) |
A. James Teague: | ||||
Vesting of phantom unit awards (2) | 184,400 | $ 4,042,048 | 237,500 | $ 6,360,250 |
W. Randall Fowler: | ||||
Vesting of phantom unit awards (2) | 162,275 | $ 3,557,068 | 229,000 | $ 6,132,620 |
Vesting of profits interest award – PrivCo I (3) | 13,715 | $ 348,910 | ||
Graham W. Bacon: | ||||
Vesting of phantom unit awards (2) | 75,250 | $ 1,649,480 | 91,250 | $ 2,443,675 |
Brent B. Secrest: | ||||
Vesting of phantom unit awards (2) | 52,500 | $ 1,150,800 | 81,250 | $ 2,175,875 |
Vesting of profits interest award – PubCo II (3) | 7,439 | $ 189,248 | ||
Christian M. Nelly: | ||||
R. Daniel Boss: | ||||
Vesting of phantom unit awards (2) | 23,005 | $ 504,270 | 62,000 | $ 1,660,360 |
Vesting of profits interest award – PubCo II (3) | 5,951 | $ 151,393 |
(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 | Unit Awards | |||||
Market | Market | |||||
Number | Value | Number | Value | |||
of Units | of Units | of Units | of Units | |||
That Have | That Have | That Have | That Have | |||
Not Vested | Not Vested | Not Vested | Not Vested | |||
Award Type/Named Executive Officer | (#) (1) | ($) (2,3) | (#) (1) | ($) (2,3) | ||
Phantom unit awards: (4) | ||||||
A. James Teague | 564,400 | $ 12,394,224 | 680,000 | $ 17,918,000 | ||
W. Randall Fowler | 540,775 | 11,875,419 | 680,000 | 17,918,000 | ||
Graham W. Bacon | 222,000 | 4,875,120 | 241,250 | 6,356,938 | ||
Brent B. Secrest | 193,750 | 4,254,750 | 241,250 | 6,356,938 | ||
Christian M. Nelly | 130,500 | 2,865,780 | ||||
R. Daniel Boss | 208,000 | 5,480,800 | ||||
Profits interest awards: | ||||||
Graham W. Bacon: | ||||||
EPD IV (5) | – | $ 0 | – | $ – | ||
Brent B. Secrest: | ||||||
EPD IV (5) | – | 0 | – | – | ||
Christian M. Nelly: | ||||||
R. Daniel Boss: | ||||||
EPD IV (5) | – | 0 | – | – |
(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 |
(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 |
(4) | Of the |
(5) | With respect to EPD IV, the profits interest share held by Messrs. Bacon, Secrest and |
• | 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, |
• | 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 $20,000 annual cash retainer. |
Fees Earned | Value of | Fees Earned | Value of | |||||||||||||||||||||
or Paid | Equity-Based | or Paid | Equity-Based | |||||||||||||||||||||
in Cash | Awards | Total | in Cash | Awards | Total | |||||||||||||||||||
Independent Voting Director | ($) | ($) | ($) | ($) | ($) | ($) | ||||||||||||||||||
Carin M. Barth | $ | 90,000 | $ | 90,000 | $ | 180,000 | $ | 95,000 | $ | 90,000 | $ | 185,000 | ||||||||||||
Murray E. Brasseux | 90,000 | 90,000 | 180,000 | 110,000 | 90,000 | 200,000 | ||||||||||||||||||
Rebecca G. Followill | 110,000 | 90,000 | 200,000 | |||||||||||||||||||||
James T. Hackett (1) | 105,000 | 90,000 | 195,000 | 115,000 | 90,000 | 205,000 | ||||||||||||||||||
William C. Montgomery (2) | 110,000 | 90,000 | 200,000 | 135,000 | 90,000 | 225,000 | ||||||||||||||||||
John R. Rutherford | 90,000 | 90,000 | 180,000 | 92,500 | 90,000 | 182,500 | ||||||||||||||||||
Richard S. Snell | 90,000 | 90,000 | 180,000 |
(1) | Mr. Hackett serves as chairman of the Governance Committee. |
(2) | Mr. Montgomery serves as chairman of the Audit and Conflicts Committee. |
Amount and | Amount and | |||||
Nature of | Nature of | |||||
Name and Address | Beneficial | Percent | Beneficial | Percent | ||
of Beneficial Owner | Title of Class | Ownership | of Class | Title of Class | Ownership | of Class |
Randa Duncan Williams (1) | Common Units | 702,377,022 | 32.3% | Common Units | 702,452,294 | 32.4% |
1100 Louisiana Street, 10th 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 | Amount and | |||||||||||
Positions with | Nature Of | Positions with | Nature Of | |||||||||
Enterprise GP | Beneficial | Percent of | Enterprise GP | Beneficial | Percent of | |||||||
at February 18, 2022 | Ownership | Class | at February 16, 2024 | Ownership | Class | |||||||
Randa Duncan Williams: | Director and Chairman of the Board | Director and Chairman of the Board | ||||||||||
Units controlled by EPCO Voting Trust: | ||||||||||||
Through EPCO | 74,754,703 | 3.4% | 74,754,703 | 3.4% | ||||||||
Through EPCO Holdings, Inc. | 597,110,600 | 27.4% | 597,110,600 | 27.5% | ||||||||
Through Employee Partnerships | 8,000,000 | * | 8,000,000 | * | ||||||||
Units controlled by Alkek and Williams, Ltd. | 491,280 | * | 558,315 | * | ||||||||
Units controlled by Chaswil, Ltd. | 81,758 | * | 92,913 | * | ||||||||
Units controlled by family trusts (1) | 21,540,424 | * | 21,070,501 | * | ||||||||
Units owned personally (2) | 398,257 | * | 865,262 | * | ||||||||
Total for Randa Duncan Williams | 702,377,022 | 32.3% | 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 | Common Units | |||||||||||
Amount and | Amount and | |||||||||||
Positions with | Nature Of | Positions with | Nature Of | |||||||||
Enterprise GP | Beneficial | Percent of | Enterprise GP | Beneficial | Percent of | |||||||
at February 18, 2022 | Ownership | Class | at February 16, 2024 | Ownership | Class | |||||||
Richard H. Bachmann | Director and Vice Chairman of the Board | 1,603,174 | * | Director and Vice Chairman of the Board | 2,013,767 | * | ||||||
A. James Teague (2,3) | Director and Co-CEO | 2,395,348 | * | |||||||||
W. Randall Fowler (2,4) | Director, Co-CEO and CFO | 1,827,329 | * | |||||||||
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 | Director | 70,776 | * | Director | 101,737 | * | ||||||
Murray E. Brasseux (5) | Director | 32,123 | * | Director | 39,034 | * | ||||||
James T. Hackett (6) | Director | 283,934 | * | |||||||||
Rebecca G. Followill (6) | Director | 8,244 | * | |||||||||
James T. Hackett (7) | Director | 305,974 | * | |||||||||
William C. Montgomery | Director | 61,276 | * | Director | 118,187 | * | ||||||
John R. Rutherford | Director | 97,441 | * | Director | 150,853 | * | ||||||
Richard S. Snell (7) | Director | 93,352 | * | |||||||||
Harry P. Weitzel | Director and Executive Vice President, General Counsel and Secretary | 151,062 | * | Director and Executive Vice President, General Counsel and Secretary | 239,761 | * | ||||||
Graham W. Bacon | Executive Vice President and Chief Operating Officer | 425,349 | * | Executive Vice President and Chief Operating Officer | 538,307 | * | ||||||
Brent B. Secrest | Executive Vice President and Chief Commercial Officer | 181,570 | * | Executive Vice President and Chief Commercial Officer | 304,882 | * | ||||||
Christian M. Nelly (2) | Executive Vice President – Finance and Sustainability and Treasurer | 120,179 | * | |||||||||
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) | 709,854,425 | 32.6% | 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, | |
The number of common units presented for Mr. Teague includes (i) | |
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 |
(7) | The number of common units presented for Mr. |
• | 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 | Number of | |||||||
Units | Units | |||||||
Remaining | Remaining | |||||||
Available For | Available For | |||||||
Number of | Future Issuance | Number of | Future Issuance | |||||
Units to | Weighted- | Under Equity | Units to | Weighted- | Under Equity | |||
Be Issued | Average | Compensation | Be Issued | Average | Compensation | |||
Upon Exercise | Exercise Price | Plans (excluding | Upon Exercise | Exercise Price | Plans (excluding | |||
of Outstanding | of Outstanding | securities | of Outstanding | of Outstanding | securities | |||
Common Unit | Common Unit | reflected in | Common Unit | Common Unit | reflected in | |||
Plan Category | Plan Category | Options | Options | column (a)) | Plan Category | Options | Options | column (a)) |
(a) | (b) | (c) | (a) | (b) | (c) | |||
Equity compensation plans approved by unitholders: | Equity compensation plans approved by unitholders: | Equity compensation plans approved by unitholders: | ||||||
2008 Plan (1) | 2008 Plan (1) | – | – | 20,765,933 | 2008 Plan (1) | – | – | 109,102,487 |
Equity compensation plans not approved by unitholders: | Equity compensation plans not approved by unitholders: | Equity compensation plans not approved by unitholders: | ||||||
None | None | – | – | – | None | – | – | – |
Total for equity compensation plans | Total for equity compensation plans | – | – | 20,765,933 | Total for equity compensation plans | – | – | 109,102,487 |
(1) | At December 31, |
• | 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, | ||||||||
2021 | 2020 | |||||||
Audit fees (1) | $ | 4,841,797 | $ | 5,155,475 |
For the Year Ended December 31, | ||||||||
2023 | 2022 | |||||||
Audit fees (1) | $ | 5,386,633 | $ | 5,398,000 |
(1) | Audit fees for |
(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 | |
2.2 | |
2.3 | |
2.4 | |
2.5 | |
2.6 | |
2.7 | |
2.8 | |
2.9 |
2.10 | |
2.11 | |
2.12 | |
2.13 | |
2.14 | |
3.1 | |
3.2 | |
3.3 | |
3.4 | |
3.5 | |
3.6 | |
3.7 | |
4.1 | |
4.2 | |
4.3 |
4.4 |
4.5 | |
4.6 | |
4.7 | |
4.8 | |
4.9 | |
4.10 | |
4.11 | |
4.12 | |
4.13 | |
4.14 | |
4.15 | |
4.16 | |
4.17 |
4.18 | |
4.19 | |
4.20 | |
4.21 | |
4.22 | |
4.23 | |
4.24 | |
4.25 | |
4.26 | |
4.27 | |
4.28 | |
4.29 | |
4.30 |
4.31 | |
4.32 | |
4.33 |
4.53 | |
4.54 | |
4.55 | |
4.56 | |
4.57 | |
4.63 | |
4.64 |
4.65 | |
4.66 | |
4.67 | |
4.69 | |
4.70 | |
4.71 | |
4.72 | |
4.73 | |
4.86 | |
4.87 | |
10.1*** | |
10.2*** | |
10.3*** | |
10.4*** | |
10.5 |
21.1# | |||
22.1# | |||
23.1# | |||
31.1# | |||
31.2# | |||
32.1# | |||
32.2# | |||
97.1# | |||
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/ | ||
Executive Vice President – Accounting, Risk Control and Information Technology | ||
R. Daniel Boss |
Page No. | ||
- | Assessing whether long-lived assets having indicators of impairment were appropriately identified and further tested for impairment. |
- | Comparing the |
- | Reading publicly available information for the industry, peers, and customers to determine whether a potential impairment indicator was not contemplated in management’s analysis. |
- | Reading minutes of the Board of Directors to understand if there were factors that could represent a potential impairment indicator not contemplated in management’s analysis. |
December 31, | ||||||||
2021 | 2020 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 2,819.4 | $ | 1,059.9 | ||||
Restricted cash | 145.3 | 98.2 | ||||||
Accounts receivable – trade, net of allowance for credit losses of $52.7 at December 31, 2021 and $46.5 at December 31, 2020 | 6,967.2 | 4,802.6 | ||||||
Accounts receivable – related parties | 20.6 | 5.6 | ||||||
Inventories | 2,681.0 | 3,303.5 | ||||||
Derivative assets (see Note 13) | 236.5 | 228.6 | ||||||
Prepaid and other current assets | 399.4 | 411.0 | ||||||
Total current assets | 13,269.4 | 9,909.4 | ||||||
Property, plant and equipment, net (see Note 4) | 42,087.7 | 41,912.8 | ||||||
Investments in unconsolidated affiliates | 2,428.4 | 2,429.2 | ||||||
Intangible assets, net (see Note 6) | 3,150.6 | 3,309.1 | ||||||
Goodwill (see Note 6) | 5,448.9 | 5,448.9 | ||||||
Other assets | 1,140.6 | 1,097.3 | ||||||
Total assets | $ | 67,525.6 | $ | 64,106.7 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Current maturities of debt (see Note 7) | $ | 1,399.8 | $ | 1,325.0 | ||||
Accounts payable – trade | 632.0 | 704.6 | ||||||
Accounts payable – related parties | 166.6 | 149.5 | ||||||
Accrued product payables | 8,093.3 | 5,395.4 | ||||||
Accrued interest | 452.7 | 455.6 | ||||||
Derivative liabilities (see Note 13) | 254.2 | 349.2 | ||||||
Other current liabilities | 625.9 | 608.7 | ||||||
Total current liabilities | 11,624.5 | 8,988.0 | ||||||
Long-term debt (see Note 7) | 28,135.3 | 28,540.7 | ||||||
Deferred tax liabilities (see Note 15) | 518.0 | 464.7 | ||||||
Other long-term liabilities | 760.0 | 686.6 | ||||||
Commitments and contingent liabilities (see Note 16) | 0 | 0 | ||||||
Redeemable preferred limited partner interests: (see Note 8) | ||||||||
Series A cumulative convertible preferred units (“preferred units”) (50,412 units outstanding at December 31, 2021 and 50,138 units outstanding at December 31, 2020) | 49.3 | 49.3 | ||||||
Equity: (see Note 8) | ||||||||
Partners’ equity: | ||||||||
Common limited partner interests (2,176,379,587 units issued and outstanding at December 31, 2021 and 2,182,308,958 units issued and outstanding at December 31, 2020) | 26,340.3 | 25,766.6 | ||||||
Treasury units, at cost | (1,297.3 | ) | (1,297.3 | ) | ||||
Accumulated other comprehensive income (loss) | 285.9 | (165.2 | ) | |||||
Total partners’ equity | 25,328.9 | 24,304.1 | ||||||
Noncontrolling interests in consolidated subsidiaries | 1,109.6 | 1,073.3 | ||||||
Total equity | 26,438.5 | 25,377.4 | ||||||
Total liabilities, preferred units, and equity | $ | 67,525.6 | $ | 64,106.7 |
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, | ||||||||||||
2021 | 2020 | 2019 | ||||||||||
Revenues: | ||||||||||||
Third parties | $ | 40,726.8 | $ | 27,163.0 | $ | 32,721.9 | ||||||
Related parties | 80.1 | 36.7 | 67.3 | |||||||||
Total revenues (see Note 9) | 40,806.9 | 27,199.7 | 32,789.2 | |||||||||
Costs and expenses: | ||||||||||||
Operating costs and expenses: | ||||||||||||
Third party and other costs | 33,790.5 | 21,160.5 | 25,649.8 | |||||||||
Related parties | 1,286.8 | 1,210.6 | 1,412.0 | |||||||||
Total operating costs and expenses | 35,077.3 | 22,371.1 | 27,061.8 | |||||||||
General and administrative costs: | ||||||||||||
Third party and other costs | 75.9 | 83.4 | 75.3 | |||||||||
Related parties | 133.4 | 136.2 | 136.4 | |||||||||
Total general and administrative costs | 209.3 | 219.6 | 211.7 | |||||||||
Total costs and expenses (see Note 10) | 35,286.6 | 22,590.7 | 27,273.5 | |||||||||
Equity in income of unconsolidated affiliates | 583.4 | 426.1 | 563.0 | |||||||||
Operating income | 6,103.7 | 5,035.1 | 6,078.7 | |||||||||
Other income (expense): | ||||||||||||
Interest expense | (1,283.0 | ) | (1,287.4 | ) | (1,243.0 | ) | ||||||
Change in fair market value of Liquidity Option | 0 | (2.3 | ) | (119.6 | ) | |||||||
Interest income | 4.7 | 13.4 | 11.6 | |||||||||
Other, net | (0.1 | ) | 2.6 | 5.0 | ||||||||
Total other expense, net | (1,278.4 | ) | (1,273.7 | ) | (1,346.0 | ) | ||||||
Income before income taxes | 4,825.3 | 3,761.4 | 4,732.7 | |||||||||
Benefit from (provision for) income taxes (see Note 15) | (70.0 | ) | 124.3 | (45.6 | ) | |||||||
Net income | 4,755.3 | 3,885.7 | 4,687.1 | |||||||||
Net income attributable to noncontrolling interests (see Note 8) | (117.6 | ) | (110.1 | ) | (95.8 | ) | ||||||
Net income attributable to preferred units (see Note 8) | (3.6 | ) | (0.9 | ) | 0 | |||||||
Net income attributable to common unitholders | $ | 4,634.1 | $ | 3,774.7 | $ | 4,591.3 | ||||||
Earnings per unit: (see Note 11) | ||||||||||||
Basic earnings per common unit | $ | 2.11 | $ | 1.71 | $ | 2.09 | ||||||
Diluted earnings per common unit | $ | 2.10 | $ | 1.71 | $ | 2.09 |
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, | ||||||||||||
2021 | 2020 | 2019 | ||||||||||
Net income | $ | 4,755.3 | $ | 3,885.7 | $ | 4,687.1 | ||||||
Other comprehensive income (loss): | ||||||||||||
Cash flow hedges: (see Note 13) | ||||||||||||
Commodity hedging derivative instruments: | ||||||||||||
Changes in fair value of cash flow hedges | (677.7 | ) | 124.4 | 44.1 | ||||||||
Reclassification of losses (gains) to net income | 907.8 | (272.7 | ) | (141.7 | ) | |||||||
Interest rate hedging derivative instruments: | ||||||||||||
Changes in fair value of cash flow hedges | 182.9 | (127.5 | ) | 81.4 | ||||||||
Reclassification of losses to net income | 38.3 | 39.3 | 37.3 | |||||||||
Total cash flow hedges | 451.3 | (236.5 | ) | 21.1 | ||||||||
Other | (0.2 | ) | (0.1 | ) | (0.6 | ) | ||||||
Total other comprehensive income (loss) | 451.1 | (236.6 | ) | 20.5 | ||||||||
Comprehensive income | 5,206.4 | 3,649.1 | 4,707.6 | |||||||||
Comprehensive income attributable to noncontrolling interests | (117.6 | ) | (110.1 | ) | (95.8 | ) | ||||||
Comprehensive income attributable to preferred units (see Note 8) | (3.6 | ) | (0.9 | ) | 0 | |||||||
Comprehensive income attributable to common unitholders | $ | 5,085.2 | $ | 3,538.1 | $ | 4,611.8 |
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, | ||||||||||||
2021 | 2020 | 2019 | ||||||||||
Operating activities: | ||||||||||||
Net income | $ | 4,755.3 | $ | 3,885.7 | $ | 4,687.1 | ||||||
Reconciliation of net income to net cash flows provided by operating activities: | ||||||||||||
Depreciation and accretion | 1,723.5 | 1,696.6 | 1,570.0 | |||||||||
Amortization of intangible assets | 150.9 | 143.2 | 174.7 | |||||||||
Amortization of major maintenance costs for reaction-based plants | 26.9 | 0 | 0 | |||||||||
Other amortization expense | 238.5 | 232.1 | 204.6 | |||||||||
Impairment of goodwill (see Notes 2 and 6) | 0 | 296.3 | 0 | |||||||||
Impairment of assets other than goodwill (see Notes 2 and 4) | 232.8 | 594.3 | 132.8 | |||||||||
Equity in income of unconsolidated affiliates | (583.4 | ) | (426.1 | ) | (563.0 | ) | ||||||
Distributions received from unconsolidated affiliates attributable to earnings | 543.8 | 426.6 | 568.0 | |||||||||
Net losses (gains) attributable to asset sales and related matters (see Note 18) | 5.5 | (4.4 | ) | (5.7 | ) | |||||||
Deferred income tax expense (benefit) | 39.8 | (147.6 | ) | 20.0 | ||||||||
Change in fair market value of derivative instruments | (27.4 | ) | (79.3 | ) | 27.2 | |||||||
Change in fair market value of Liquidity Option | 0 | 2.3 | 119.6 | |||||||||
Non-cash expense related to long-term operating leases (see Note 16) | 40.6 | 39.0 | 42.8 | |||||||||
Net effect of changes in operating accounts (see Note 18) | 1,366.7 | (767.5 | ) | (457.4 | ) | |||||||
Other operating activities | (1.0 | ) | 0.3 | (0.2 | ) | |||||||
Net cash flows provided by operating activities | 8,512.5 | 5,891.5 | 6,520.5 | |||||||||
Investing activities: | ||||||||||||
Capital expenditures | (2,223.2 | ) | (3,287.9 | ) | (4,531.7 | ) | ||||||
Investments in unconsolidated affiliates | (2.1 | ) | (15.6 | ) | (111.6 | ) | ||||||
Distributions received from unconsolidated affiliates attributable to the return of capital | 46.3 | 187.5 | 63.3 | |||||||||
Proceeds from asset sales (see Note 18) | 64.3 | 12.8 | 20.6 | |||||||||
Other investing activities | (19.9 | ) | (17.5 | ) | (16.1 | ) | ||||||
Cash used in investing activities | (2,134.6 | ) | (3,120.7 | ) | (4,575.5 | ) | ||||||
Financing activities: | ||||||||||||
Borrowings under debt agreements | 11,158.5 | 6,672.1 | 58,172.6 | |||||||||
Repayments of debt | (11,491.8 | ) | (4,406.6 | ) | (56,716.5 | ) | ||||||
Debt issuance costs | (15.6 | ) | (46.3 | ) | (27.6 | ) | ||||||
Monetization of interest rate derivative instruments (see Note 13) | 75.2 | (33.3 | ) | 0 | ||||||||
Cash distributions paid to common unitholders (see Note 8) | (3,930.4 | ) | (3,891.0 | ) | (3,839.8 | ) | ||||||
Cash payments made in connection with distribution equivalent rights | (30.9 | ) | (27.1 | ) | (22.1 | ) | ||||||
Cash distributions paid to noncontrolling interests (see Note 8) | (153.7 | ) | (131.3 | ) | (106.2 | ) | ||||||
Cash contributions from noncontrolling interests (see Note 8) | 72.4 | 30.9 | 632.8 | |||||||||
Net cash proceeds from the issuance of common units | 0 | 0 | 82.2 | |||||||||
Repurchase of common units under 2019 Buyback Program (see Note 8) | (213.9 | ) | (186.3 | ) | (81.1 | ) | ||||||
Net cash proceeds from the issuance of preferred units (see Note 8) | 0 | 31.5 | 0 | |||||||||
Other financing activities | (41.1 | ) | (35.3 | ) | (39.4 | ) | ||||||
Cash used in financing activities | (4,571.3 | ) | (2,022.7 | ) | (1,945.1 | ) | ||||||
Net change in cash and cash equivalents, including restricted cash | 1,806.6 | 748.1 | (0.1 | ) | ||||||||
Cash and cash equivalents, including restricted cash, January 1 | 1,158.1 | 410.0 | 410.1 | |||||||||
Cash and cash equivalents, including restricted cash, December 31 | $ | 2,964.7 | $ | 1,158.1 | $ | 410.0 |
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, 2018 | $ | 23,802.6 | $ | 0 | $ | 50.9 | $ | 438.7 | $ | 24,292.2 | ||||||||||
Net income | 4,591.3 | 0 | 0 | 95.8 | 4,687.1 | |||||||||||||||
Cash distributions paid to common unitholders | (3,839.8 | ) | 0 | 0 | 0 | (3,839.8 | ) | |||||||||||||
Cash payments made in connection with distribution equivalent rights | (22.1 | ) | 0 | 0 | 0 | (22.1 | ) | |||||||||||||
Cash distributions paid to noncontrolling interests | 0 | 0 | 0 | (106.2 | ) | (106.2 | ) | |||||||||||||
Cash contributions from noncontrolling interests | 0 | 0 | 0 | 632.8 | 632.8 | |||||||||||||||
Net cash proceeds from the issuance of common units | 82.2 | 0 | 0 | 0 | 82.2 | |||||||||||||||
Common units issued in connection with employee compensation | 45.6 | 0 | 0 | 0 | 45.6 | |||||||||||||||
Repurchase and cancellation of common units under 2019 Buyback Program | (81.1 | ) | 0 | 0 | 0 | (81.1 | ) | |||||||||||||
Amortization of fair value of equity-based awards | 143.3 | 0 | 0 | 0 | 143.3 | |||||||||||||||
Cash flow hedges | 0 | 0 | 21.1 | 0 | 21.1 | |||||||||||||||
Other, net | (29.4 | ) | 0 | (0.6 | ) | 2.4 | (27.6 | ) | ||||||||||||
Balance, December 31, 2019 | 24,692.6 | 0 | 71.4 | 1,063.5 | 25,827.5 | |||||||||||||||
Net income | 3,774.7 | 0 | 0 | 110.1 | 3,884.8 | |||||||||||||||
Cash distributions paid to common unitholders | (3,891.0 | ) | 0 | 0 | 0 | (3,891.0 | ) | |||||||||||||
Cash payments made in connection with distribution equivalent rights | (27.1 | ) | 0 | 0 | 0 | (27.1 | ) | |||||||||||||
Cash distributions paid to noncontrolling interests | 0 | 0 | 0 | (131.3 | ) | (131.3 | ) | |||||||||||||
Cash contributions from noncontrolling interests | 0 | 0 | 0 | 30.9 | 30.9 | |||||||||||||||
Repurchase and cancellation of common units under 2019 Buyback Program | (186.3 | ) | 0 | 0 | 0 | (186.3 | ) | |||||||||||||
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option (see Note 8) | 1,297.3 | 0 | 0 | 0 | 1,297.3 | |||||||||||||||
Treasury units acquired in connection with settlement of Liquidity Option, at cost (see Note 8) | 0 | (1,297.3 | ) | 0 | 0 | (1,297.3 | ) | |||||||||||||
Common units exchanged for preferred units, with common units received being immediately cancelled (see Note 8) | (17.5 | ) | 0 | 0 | 0 | (17.5 | ) | |||||||||||||
Amortization of fair value of equity-based awards | 158.6 | 0 | 0 | 0 | 158.6 | |||||||||||||||
Cash flow hedges | 0 | 0 | (236.5 | ) | 0 | (236.5 | ) | |||||||||||||
Other, net | (34.7 | ) | 0 | (0.1 | ) | 0.1 | (34.7 | ) | ||||||||||||
Balance, December 31, 2020 | 25,766.6 | (1,297.3 | ) | (165.2 | ) | 1,073.3 | 25,377.4 | |||||||||||||
Net income | 4,634.1 | 0 | 0 | 117.6 | 4,751.7 | |||||||||||||||
Cash distributions paid to common unitholders | (3,930.4 | ) | 0 | 0 | 0 | (3,930.4 | ) | |||||||||||||
Cash payments made in connection with distribution equivalent rights | (30.9 | ) | 0 | 0 | 0 | (30.9 | ) | |||||||||||||
Cash distributions paid to noncontrolling interests | 0 | 0 | 0 | (153.7 | ) | (153.7 | ) | |||||||||||||
Cash contributions from noncontrolling interests | 0 | 0 | 0 | 72.4 | 72.4 | |||||||||||||||
Repurchase and cancellation of common units under 2019 Buyback Program | (213.9 | ) | 0 | 0 | 0 | (213.9 | ) | |||||||||||||
Amortization of fair value of equity-based awards | 151.1 | 0 | 0 | 0 | 151.1 | |||||||||||||||
Cash flow hedges | 0 | 0 | 451.3 | 0 | 451.3 | |||||||||||||||
Other, net | (36.3 | ) | 0 | (0.2 | ) | 0 | (36.5 | ) | ||||||||||||
Balance, December 31, 2021 | $ | 26,340.3 | $ | (1,297.3 | ) | $ | 285.9 | $ | 1,109.6 | $ | 26,438.5 |
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 |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||||||||||
2021 | 2020 | 2019 | 2023 | 2022 | 2021 | |||||||||||||||||||
Balance at beginning of period | $ | 46.5 | $ | 12.4 | $ | 11.5 | $ | 54 | $ | 53 | $ | 47 | ||||||||||||
Charged to costs and expenses | 7.2 | 8.4 | 1.2 | 1 | 6 | 7 | ||||||||||||||||||
Charged to other accounts | 4.4 | 28.7 | 0 | – | 1 | 4 | ||||||||||||||||||
Deductions | (5.4 | ) | (3.0 | ) | (0.3 | ) | (20 | ) | (6 | ) | (5 | ) | ||||||||||||
Balance at end of period | $ | 52.7 | $ | 46.5 | $ | 12.4 | $ | 35 | $ | 54 | $ | 53 |
December 31, | December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
Cash and cash equivalents | $ | 2,819.4 | $ | 1,059.9 | $ | 180 | $ | 76 | ||||||||
Restricted cash | 145.3 | 98.2 | 140 | 130 | ||||||||||||
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows | $ | 2,964.7 | $ | 1,158.1 | $ | 320 | $ | 206 |
For the Year Ended December 31, | ||||||||||||
2021 | 2020 | 2019 | ||||||||||
Balance at beginning of period | $ | 4.5 | $ | 7.2 | $ | 6.9 | ||||||
Charged to costs and expenses | 5.5 | 6.2 | 12.3 | |||||||||
Acquisition-related additions and other | 1.3 | 2.6 | 2.5 | |||||||||
Deductions | (7.6 | ) | (11.5 | ) | (14.5 | ) | ||||||
Balance at end of period | $ | 3.7 | $ | 4.5 | $ | 7.2 |
• | Level 1 fair value measures. Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., transactions on the New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”)). Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments. |
• | Level 2 fair value measures. Level 2 fair values are based on pricing inputs other than quoted prices in active markets (a Level 1 fair value measure) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations. The fair value of our interest rate derivatives are determined using financial models that incorporate third-party yield curves for the same period as the future interest rate |
• | Level 3 fair value measures. Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect management’s ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed forecasts. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of fair value. Valuations using Level 3 inputs are reviewed and approved by members of senior management. |
For the Year Ended December 31, | ||||||||||||
2021 | 2020 | 2019 | ||||||||||
Impairment charges reflected in operating costs and expenses: | ||||||||||||
Property, plant and equipment (see Note 4) | $ | 217.7 | $ | 589.8 | $ | 51.0 | ||||||
Investment in unconsolidated affiliate (see Note 5) | 0 | 0 | 76.4 | |||||||||
Goodwill (see Note 6) | 0 | 296.3 | 0 | |||||||||
Other (1) | 14.9 | 4.5 | 5.3 | |||||||||
Total asset impairment charges in operating costs and expenses | 232.6 | 890.6 | 132.7 | |||||||||
Other property, plant and equipment impairment charges (2) | 0.2 | 0 | 0.1 | |||||||||
Total asset impairment charges | $ | 232.8 | $ | 890.6 | $ | 132.8 |
For the Year Ended December 31, | ||||||||||||
2023 | 2022 | 2021 | ||||||||||
Impairment charges reflected in operating costs and expenses: | ||||||||||||
Property, plant and equipment | $ | 18 | $ | 41 | $ | 218 | ||||||
Other (1) | 12 | 12 | 15 | |||||||||
Total asset impairment charges in operating costs and expenses (2) | 30 | 53 | 233 | |||||||||
Other property, plant and equipment impairment charges (3) | 2 | – | – | |||||||||
Total asset impairment charges | $ | 32 | $ | 53 | $ | 233 |
(1) | Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill. |
(2) | Amounts presented are |
(3) | Amounts presented are a component of “Third party and other costs” within the “General and administrative |
• | Impairment Testing for Long-Lived Assets. Long-lived assets, which consist of intangible assets with finite lives and property, plant and equipment, are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note 4 for information regarding impairment charges attributable to property, plant and equipment. |
• | Impairment Testing for Investments in Unconsolidated Affiliates. We evaluate our equity method investments for impairment when there are events or changes in circumstances that indicate there is a potential loss in value of the investment attributable to an other-than-temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry. In the event we determine that the value of an investment is not recoverable due to an other-than-temporary decline, we record a non-cash impairment charge to adjust the carrying value of the investment to its estimated fair value. We did not record any non-cash impairment charges related to our equity method investments during the years ended December 31, 2023, 2022 or 2021. See Note 5 for information regarding |
• | Impairment Testing for Goodwill. Goodwill, which represents the cost of an acquired business in excess of the fair value of its net assets at the acquisition date, is subject to annual impairment testing in the fourth quarter of each year or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. We test goodwill for impairment at the reporting unit (or operating segment) level following guidance in ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill |
December 31, | December 31, | |||||||||||||||
2021 | 2020 | 2023 | 2022 | |||||||||||||
NGLs | $ | 2,026.6 | $ | 1,888.1 | $ | 2,392 | $ | 1,689 | ||||||||
Petrochemicals and refined products | 343.0 | 642.6 | 536 | 430 | ||||||||||||
Crude oil | 285.4 | 758.1 | 419 | 411 | ||||||||||||
Natural gas | 26.0 | 14.7 | 5 | 24 | ||||||||||||
Total | $ | 2,681.0 | $ | 3,303.5 | $ | 3,352 | $ | 2,554 |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||||||||||
2021 | 2020 | 2019 | 2023 | 2022 | 2021 | |||||||||||||||||||
Cost of sales (1) | $ | 29,887.0 | $ | 16,723.2 | $ | 22,065.8 | $ | 37,023 | $ | 45,836 | $ | 29,887 | ||||||||||||
Lower of cost or net realizable value adjustments recognized in cost of sales | 20.1 | 60.2 | 22.7 | 31 | 19 | 20 |
(1) | Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities. |
Estimated Useful Life | December 31, | Estimated Useful Life | December 31, | |||||||||||||||||||||
in Years | 2021 | 2020 | in Years | 2023 | 2022 | |||||||||||||||||||
Plants, pipelines and facilities | 3-45 | (5) | $ | 51,635.6 | $ | 49,972.8 | 3-45 | $ | 57,983 | $ | 54,396 | |||||||||||||
Underground and other storage facilities | 5-40 | (6) | 4,327.3 | 4,207.5 | 5-40 | 4,401 | 4,329 | |||||||||||||||||
Transportation equipment (3) | 3-10 | 208.9 | 204.9 | 3-10 | 242 | 222 | ||||||||||||||||||
Marine vessels (4) | 15-30 | 918.1 | 932.7 | 15-30 | 935 | 921 | ||||||||||||||||||
Land | 379.1 | 371.9 | 411 | 387 | ||||||||||||||||||||
Construction in progress | 1,616.4 | 1,807.7 | 2,245 | 2,867 | ||||||||||||||||||||
Subtotal | 59,085.4 | 57,497.5 | 66,217 | 63,122 | ||||||||||||||||||||
Less accumulated depreciation | 17,083.0 | 15,584.7 | 20,462 | 18,800 | ||||||||||||||||||||
Subtotal property, plant and equipment, net | 42,002.4 | 41,912.8 | 45,755 | 44,322 | ||||||||||||||||||||
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7) | 85.3 | 0 | 49 | 79 | ||||||||||||||||||||
Property, plant and equipment, net | $ | 42,087.7 | $ | 41,912.8 | $ | 45,804 | $ | 44,401 |
(1) | Plants, pipelines and facilities include |
(2) | Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. |
(3) | Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. |
(4) | Marine vessels include tow boats, barges and related equipment used in our marine transportation business. |
(5) | In general, the estimated useful lives of major assets within this category are: |
(6) | In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years. |
(7) | For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||||||||||
2021 | 2020 | 2019 | 2023 | 2022 | 2021 | |||||||||||||||||||
Depreciation expense (1) | $ | 1,705.5 | $ | 1,681.9 | $ | 1,562.6 | $ | 1,860 | $ | 1,779 | $ | 1,705 | ||||||||||||
Capitalized interest (2) | 79.6 | 115.0 | 143.8 | 106 | 90 | 80 |
(1) | Depreciation expense is a component of “Third party and other costs” within “Costs and expenses” as presented on our Statements of Consolidated Operations. |
(2) | Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations. |
For the Year Ended December 31, | For the Year Ended December 31, | |||||||||||||||||||||||
2021 | 2020 | 2019 | 2023 | 2022 | 2021 | |||||||||||||||||||
ARO liability beginning balance | $ | 149.5 | $ | 132.1 | $ | 126.3 | $ | 234 | $ | 176 | $ | 150 | ||||||||||||
Liabilities incurred (1) | 6.5 | 4.6 | 5.0 | 5 | 20 | 6 | ||||||||||||||||||
Revisions in estimated cash flows (2) | 5.9 | (0.4 | ) | (4.3 | ) | (12 | ) | 30 | 6 | |||||||||||||||
Liabilities settled (3) | (3.5 | ) | (1.5 | ) | (2.3 | ) | (13 | ) | (10 | ) | (4 | ) | ||||||||||||
Accretion expense (4) | 18.0 | 14.7 | 7.4 | 11 | 18 | 18 | ||||||||||||||||||
ARO liability ending balance | $ | 176.4 | $ | 149.5 | $ | 132.1 | $ | 225 | $ | 234 | $ | 176 |
(1) | Represents the initial recognition of estimated ARO liabilities during period. |
(2) | Represents subsequent adjustments to estimated ARO liabilities during period. |
(3) | Represents cash payments to settle ARO liabilities during period. |
(4) | Represents net change in ARO liability balance attributable to the passage of time and other adjustments, including true-up amounts associated with revised closure estimates. |
2022 | 2023 | 2024 | 2025 | 2026 | ||||||||||||||||||||||||||||||||
2024 | 2024 | 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||||||||||||||
$ | 9.5 | $ | 10.1 | $ | 10.7 | $ | 11.4 | $ | 12.1 | 13 | $ | 14 | $ | 15 | $ | 16 | $ | 16 |
For the Year Ended December 31, | ||||||||||||
2021 | 2020 | 2019 | ||||||||||
NGL Pipelines & Services: | ||||||||||||
South Texas natural gas processing plants | $ | 0 | $ | 86.9 | $ | 15.6 | ||||||
Other | 20.2 | 121.2 | 23.5 | |||||||||
Crude Oil Pipelines & Services: | ||||||||||||
Cancellation of Midland-to-ECHO 4 project | 0 | 42.2 | ||||||||||
Other | 14.6 | 3.3 | 2.6 | |||||||||
Natural Gas Pipelines & Services: | ||||||||||||
Val Verde gathering system and treating facility | 37.5 | |||||||||||
South Texas natural gas gathering pipelines | 0 | 37.8 | ||||||||||
Other | 18.9 | 5.5 | 4.8 | |||||||||
Petrochemical & Refined Products Services: | ||||||||||||
Marine transportation business | 112.5 | 252.1 | ||||||||||
Other | 14.0 | 40.8 | 4.6 | |||||||||
Total impairment charges for property, plant and equipment | $ | 217.7 | $ | 589.8 | $ | 51.1 |
For the Year Ended December 31, | ||||||||||||
2023 | 2022 | 2021 | ||||||||||
NGL Pipelines & Services | $ | 12 | $ | 23 | $ | 20 | ||||||
Crude Oil Pipelines & Services | 1 | 3 | 15 | |||||||||
Natural Gas Pipelines & Services (1) | 5 | 6 | 56 | |||||||||
Petrochemical & Refined Products Services (2) | 2 | 9 | 127 | |||||||||
Total impairment charges for property, plant and equipment | $ | 20 | $ | 41 | $ | 218 |
(1) | 2021 amount includes a $37 million non-cash impairment charge associated with the sale of components of our San Juan Gathering System. |
(2) | 2021 amount includes a non-cash impairment charge of $113 million associated with our marine transportation business. |
• | In December 2021, we evaluated our marine transportation business for impairment due to a further deterioration of demand for such services, which resulted in lower-than-expected term and spot rates. As a result of our review, we recognized an impairment charge of |
• | In March 2021, we entered into agreements to sell a coal bed natural gas gathering system and related Val Verde treating facility, both of which were components of our San Juan Gathering System, to a third party for $39 million in cash. The transaction closed and was effective on April 1, 2021. We
Note 5. Investments in Unconsolidated Affiliates The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method.
NGL Pipelines & Services The principal business activity of each investee included in our NGL Pipelines & Services segment is described as follows:
Crude Oil Pipelines & Services The principal business activity of each investee included in our Crude Oil Pipelines & Services segment is described as follows:
Natural Gas Pipelines & Services The principal business activity of each investee included in our Natural Gas Pipelines & Services segment is described as follows:
Petrochemical & Refined Products Services The principal business activity of each investee included in our Petrochemical & Refined Products Services segment is described as follows:
Equity Earnings The following table presents our equity in income
Note 6. Intangible Assets and Goodwill Identifiable Intangible Assets The following table summarizes our intangible assets by business segment at the dates indicated:
The following table presents the amortization expense of our intangible assets by business segment for the years indicated:
The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated:
Customer relationship intangible assets Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. Our customer relationship intangible assets are classified as either (i) basin-specific or (ii) general. Basin-specific customer relationships represent access to customers associated with a defined resource basin (e.g., customers using a natural gas gathering system serving a specific production field) and is analogous to having a franchise in a particular area. General customer relationships are associated with customers whose hydrocarbon volumes are not attributable to specific resource basins (e.g., customers at a marine terminal that handles volumes originating from multiple sources). The estimated fair value of each customer relationship intangible asset was determined at the time of acquisition using a discounted cash flow analysis, which incorporates various assumptions regarding the acquired business. The assumptions may include Level 3 fair value inputs, including long-range cash flow forecasts that extend for the estimated economic life of the hydrocarbon resource base served by the asset network, anticipated service contract renewals, resource base depletion rates and expected customer attrition rates. The recognition of customer relationships are supported by a variety of factors. In general, midstream infrastructure requires a significant investment, both in terms of initial construction costs and ongoing maintenance, and is generally supported by long-term contracts that establish a customer base. The level of expenditures and regulatory requirements involved in constructing new midstream asset networks can create significant economic barriers to entry that may limit potential competition. Furthermore, efficient, continuous operation of the acquired fixed assets not only supports the commercial relationships existing at the time of the acquisition, but it provides us with opportunities to establish new ones. These factors support the long-term value attributed to our customer relationship intangible assets. With respect to amortization periods, the duration of a basin-specific customer relationship is limited to the estimated economic life of the associated resource basin. The duration of our other customer relationships is typically limited to the term of the underlying service contracts, including assumed renewals. Amortization expense attributable to customer relationships is recorded in a manner that closely resembles the pattern in which we expect to benefit from such relationships. At December 31,
• The EFS Midstream customer relationships provide us with long-term access to condensate and natural gas producers in the Eagle Ford Shale served by our EFS Midstream System. The EFS Midstream System provides condensate gathering and processing services along with gathering, treating and compression services for associated natural gas.
Contract-based intangible assets Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations. These intangible assets are typically valued using an income approach that incorporate the terms of the agreements. At December 31,
Goodwill Goodwill represents the cost of acquired businesses in excess of the fair value of their net assets at acquisition.
Note 7. Debt Obligations The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:
References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009. Variable Interest Rates The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the year ended December 31,
Amounts borrowed under EPO’s In July 2017, the Financial Conduct Authority in the U.K. announced a desire to phase out LIBOR as a benchmark by the end of June 2023. Scheduled Maturities of Debt The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31,
EPO Debt Obligations Commercial Paper Notes EPO maintains a commercial paper program under which it may issue (and have outstanding at any time) up to $3.0 billion in aggregate principal amount of short-term notes. As a back-stop to the program, we intend to maintain a minimum aggregate available borrowing capacity under EPO’s March 2023 $1.5 Billion 364-Day Revolving Credit Agreement In Under the terms of the The EPO’s obligations under the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement In Under the terms of the The EPO’s obligations under the Senior Notes EPO’s fixed-rate senior notes are unsecured obligations of EPO that rank equal with its existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. EPO’s senior notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict its ability (with certain exceptions) to incur debt secured by liens and engage in sale and leaseback transactions. In total, EPO issued In EPO’s senior notes are unconditionally guaranteed on an unsecured and unsubordinated basis by the Partnership. EPO Junior Subordinated Notes EPO’s payment obligations under its junior subordinated notes (“junior notes”) are subordinated to all of its current and future senior indebtedness. The indenture agreement governing the junior notes allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. Subject to certain exceptions, during any period in which interest payments are deferred, neither the Partnership nor EPO can declare or make any distributions on any of our respective equity securities or make any payments on indebtedness or other obligations that rank equal with or are subordinate to the junior notes. Each series of EPO’s junior notes rank equal with each other and generally are not redeemable by EPO while such notes bear interest at a fixed annual rate. In connection with the issuance of EPO’s Junior Subordinated Notes C, EPO entered into a Replacement Capital Covenant in favor of covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed, for the benefit of such debt holders, that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities. EPO’s junior notes are unconditionally guaranteed on an unsecured and subordinated basis by the Partnership. Letters of Credit At December 31, Lender Financial Covenants We were in compliance with the financial covenants of our consolidated debt agreements at December 31, Parent-Subsidiary Guarantor Relationships The Partnership acts as guarantor of the consolidated debt obligations of EPO, with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, the Partnership would be responsible for full and unconditional repayment of such obligations. Note 8. Capital Accounts Common Limited Partner Interests The following table summarizes changes in the number of our common units outstanding since December 31,
The Partnership’s common units represent limited partner interests that give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Seventh Amended and Restated Agreement of Limited Partnership (as amended from time to time, the “Partnership Agreement”). In accordance with the Partnership Agreement, capital accounts are maintained for our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity balances presented in our consolidated financial statements prepared in accordance with GAAP. Partnership earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests. Registration Statements We have a universal shelf registration statement In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to We may issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to capital investments. Common Unit Repurchases Under 2019 Buyback Program In January 2019, we announced that the Board The Partnership repurchased Common Units Delivered Under DRIP and EUPP The Partnership has a registration statement on file with the SEC authorizing the issuance or other delivery of our common units in connection with a distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional common units. In addition to the DRIP, we have registration statements on file with the SEC authorizing the issuance or other delivery of up to 23,000,000 of our common units in connection with We have the sole discretion to determine whether common units purchased under the DRIP and EUPP will come from our authorized but unissued common units or from common units purchased on the open market by each plan’s administrator. During each of the years ended December 31, 2023, 2022 and 2021, the Partnership After taking into account the number of common units delivered under the DRIP through December 31, Common Units Issued in Connection With the Vesting of Phantom Unit Awards After taking into account tax withholding requirements, the Partnership issued Redeemable Preferred Limited Partner Interests The following table summarizes changes in the number of our preferred units outstanding since
Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by a wholly owned subsidiary, OTA Holdings, Inc. (“OTA”) for 855,915 of the Partnership’s new preferred units having an equivalent value. The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation. In March 2021, a privately held affiliate of EPCO sold its entire ownership interest in the Partnership’s preferred units to third parties. As described in the Partnership Agreement, key terms of the preferred units include the following: With respect to distribution and liquidation rights, the preferred units rank senior to the Partnership’s common units. Preferred units held by persons other than the Partnership, its subsidiaries and its affiliates generally will vote on an as-converted basis with the Partnership’s common units and have certain class voting rights with respect to certain protective matters. Holders of the preferred units are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. The Partnership is prohibited from paying distributions on its common units unless full cumulative distributions on the preferred units are paid or set aside for payment. The Partnership may satisfy its obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a holder to elect all cash and other conditions as described in the Partnership Agreement. The exchange by OTA of its common units for PIK-eligible preferred units enables the Partnership to more effectively manage its consolidated cash balances. During the year ended December 31, 2021, the Partnership made quarterly distributions to its third party and related party preferred unitholders valued at During each of the years ended December 31, 2022 and 2023, the Partnership made quarterly cash distributions to its preferred unitholders for $3 million. Subject to certain limitations, each preferred unitholder may elect to convert its preferred units on or after September 30, 2025 into a number of the Partnership’s common units equal to (a) the number of preferred units to be converted multiplied by (b) the quotient of (i) $1,000 plus any accrued and unpaid distributions per preferred unit, divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). In addition, each preferred unitholder may convert its preferred units into common units if EPO’s senior notes cease to have an investment grade rating or a Change of Control (as defined in the Partnership Agreement) occurs, in each case based on the conversion ratio specified in the Partnership Agreement. The Partnership may elect to redeem the preferred units for cash, in whole or in part, based on a redemption price outlined in the following schedule, plus any accrued and unpaid distributions at the redemption date: $1,070 per preferred unit from September 30, 2022 through September 29, 2024; $1,030 per preferred unit from September 30, 2024 through September 29, 2025; $1,010 per preferred unit from September 30, 2025 through September 29, 2026; and $1,000 per preferred unit on or after September 30, 2026; however, if a Change of Control event occurs prior to September 30, 2026, the redemption price is $1,010 per preferred unit. In connection with a redemption at the Partnership’s election, the Partnership may convert up to 50% of the preferred units being redeemed into common units (and to pay cash with respect to the remainder), with each such preferred unit being converted on the applicable redemption date into a number of common units equal to (i) the then-applicable preferred unit redemption price divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). The Partnership has agreed to prepare and file a registration statement that would permit or otherwise facilitate the public resale of any common units resulting from the conversion of the preferred units to common units. Our Consolidated Balance Sheet at December 31, Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive income (loss) primarily reflects cumulative gain or loss on derivative instruments designated and qualified as cash flow hedges from inception less gains or losses previously reclassified from accumulated other comprehensive income (loss) into earnings. Gain or loss amounts related to cash flow hedges recorded in accumulated other comprehensive income (loss) are reclassified to earnings in the same period(s) in which the underlying hedged forecasted transactions affect earnings. If it becomes probable that a forecasted transaction will not occur, the related net gain or loss in accumulated other comprehensive income (loss) is immediately reclassified into earnings. The following tables present the components of accumulated other comprehensive income (loss) as reported on our Consolidated Balance Sheets at the dates indicated:
The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the years indicated:
For information regarding our interest rate and commodity derivative instruments, see Note Noncontrolling Interests Noncontrolling interests represent third party ownership interests in our consolidated subsidiaries. The following table presents the components of noncontrolling interests as reported on our Consolidated Balance Sheets at the dates indicated:
Net income attributable to noncontrolling interests was $ On February 16, 2024, we acquired the remaining noncontrolling interest of Whitethorn and Cash Distributions The following table presents Enterprise’s declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter.
On January The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. Note 9. Revenues We classify our revenues into sales of products and midstream services. Product sales relate primarily to our various marketing activities whereas midstream services represent our other integrated businesses (i.e., gathering, processing, transportation, fractionation, storage and terminaling). The following table presents our revenues by business segment, and further by revenue type, for the years indicated:
Substantially all of our revenues are derived from contracts with customers as defined within ASC 606. The following information describes the nature of our significant revenue streams by segment and type: NGL Pipelines & Services Sales of NGLs and related products NGL marketing activities generate revenues from spot and term sales of NGLs and related products that we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and long-term contract purchases. Revenue from these sales contracts is recognized when the NGLs are sold and delivered to customers at market-based prices. Midstream services Natural gas processing utilizes service contracts that are either fee-based, commodity-based or a combination of the two. When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer’s natural gas has been processed and redelivered. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms. We recognize midstream service revenues in connection with the equity NGL fractionation generates revenue using fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., fuel costs) and are recognized in the period services are provided. NGL pipeline transportation contracts and tariffs generate revenue based on a fixed fee per gallon multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements, customers are required to ship a minimum volume with a provision that allows the shipper to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue attributable to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. NGL and related product storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers in our underground storage wells and above-ground storage tanks. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, we generally charge customers throughput fees based on volumes delivered into and subsequently withdrawn from storage, which are recognized as the service is provided. NGL import and export terminaling activities generate revenue in the period services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded. Crude Oil Pipelines & Services Sales of crude oil Crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or on the open market. Revenue from these sales contracts is recognized when crude oil is sold and delivered to customers at market-based prices. Midstream services Crude oil transportation contracts and tariffs generate revenue based upon a fixed fee per barrel multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements, customers are required to ship a minimum volume over an agreed-upon period, with make-up rights. Revenue attributable to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. Crude oil storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, customers are billed a fee per unit of volume handled at our terminals. Revenue is recognized as the terminaling service is provided. Natural Gas Pipelines & Services Sales of natural gas Natural gas marketing activities generate revenue from the sale and delivery of natural gas purchased from producers, natural gas processing facilities, and on the open market. Revenue from these sales contracts is recognized when natural gas is sold and delivered to customers at market-based prices. Midstream services Natural gas transportation contracts generate revenues based on a fee per unit of volume transported multiplied by the volume gathered or delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Revenues under transportation contracts are recognized when the volumes are transported and delivered to customers. In addition, certain of our natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved. Revenues are recognized when the firm capacity services are provided to the shipper. Petrochemical & Refined Products Services Sales of petrochemicals and refined products Our petrochemical and refined products marketing activities generate revenue from the sale and delivery of products to customers at market-based prices. The products handled by these marketing groups include polymer grade propylene, octane additives, high purity isobutylene and various refined products. Midstream services Propylene fractionation units and butane isomerization facilities generate revenue through fee-based tolling arrangements with customers. Revenue from such agreements is recognized in the period the services are provided. Petrochemical and refined products transportation contracts generate revenue based upon a fixed fee per volume multiplied by the volume transported and delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Marine transportation contracts generate revenue based on set day rates or a set fee per cargo movement recognized over the transit time of individual tows. Additionally, we record revenue for the costs of fuel and other operating costs that are directly reimbursed by our marine customers. Petrochemicals and refined products storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, customers are billed a fee per unit of volume handled at our terminals. Revenue is recognized as the terminaling service is provided. Unbilled Revenue and Deferred Revenue The following table provides information regarding our contract assets and contract liabilities at the dates indicated:
The following table presents significant changes in our unbilled revenue and deferred revenue balances during the years indicated:
Remaining Performance Obligations The following table presents estimated fixed future consideration from revenue contracts that contain minimum volume commitments, deficiency and similar fees and the term of the contracts exceeds one year. These amounts represent the revenues we expect to recognize in future periods from these contracts as of December 31, For a significant portion of our revenue, we bill customers a contractual rate for the services provided multiplied by the amount of volume handled in a given period. We have the right to invoice the customer in the amount that corresponds directly with the value of our performance completed to date. Therefore, we are not required to disclose information about the variable consideration of remaining performance obligations since we recognize revenue equal to the amount that we have the right to invoice.
Note 10. Business Segments and Related Information Segment Overview Our operations are reported under Financial information regarding these segments is evaluated regularly by our co-chief operating decision makers in deciding how to allocate resources and in assessing our operating and financial performance. The co-principal executive officers of our general partner have been identified as our co-chief operating decision makers. While these two officers evaluate results in a number of different ways, the business segment structure is the primary basis for which the allocation of resources and financial results are assessed. The following information summarizes the assets and operations of each business
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 Our plants, pipelines and other fixed assets are located in the U.S. Segment Gross Operating Margin We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. The following table presents our measurement of total segment gross operating margin for the years indicated. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income.
The results of operations from our liquids pipelines are primarily dependent upon the volumes transported and the associated fees we charge for such transportation services. Typically, pipeline transportation revenue is recognized when volumes are re-delivered to customers. However, under certain pipeline transportation agreements, customers are required to ship a minimum volume over an agreed-upon period. These arrangements may entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized under GAAP at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. However, management includes deferred transportation revenues relating to the “make-up rights” of committed shippers when reviewing the financial results of certain pipelines (Texas Express Pipeline, Front Range Pipeline, ATEX, Aegis Ethane Pipeline, and Seaway Pipeline). From an internal (and segment) reporting standpoint, management considers the transportation fees paid by committed shippers on these pipelines, including any non-refundable revenues that may be deferred under GAAP related to make-up rights, to be important in assessing the financial performance of these pipeline assets. Although the adjustments for make-up rights are included in segment gross operating margin, our consolidated revenues do not reflect any deferred revenues until the conditions for recognizing such revenues are met in accordance with GAAP. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses from segment revenues, with both segment totals reflecting the adjustments noted in the preceding table, as applicable, and before the elimination of intercompany transactions. The following table presents gross operating margin by segment for the years indicated:
Summarized Segment Financial Information Information by business segment, together with reconciliations to amounts presented on, or included in, our Statements of Consolidated Operations, is presented in the following table:
Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Our consolidated revenues reflect the elimination of intercompany transactions. We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Equity investments with industry partners are a significant component of our business strategy. They are a means by which we conduct our operations to align our interests with those of customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed. Many of these businesses perform supporting or complementary roles to our other midstream business operations. Our integrated midstream energy asset network (including the midstream energy assets owned by our unconsolidated affiliates) provides services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. In general, hydrocarbons may enter our asset system in a number of ways, such as through a natural gas gathering pipeline, natural gas processing facility, a crude oil pipeline or terminal, an NGL fractionator, an NGL storage facility or an NGL gathering or transportation pipeline. The assets of many of our equity investees are included within our integrated midstream network. For example, we use the Front Range Pipeline and Texas Express Pipeline to transport mixed NGLs to our Chambers County NGL fractionation and storage complex and the Seaway Pipeline to transport crude oil to our terminals in the Houston, Texas area. Given the integral nature of these equity method investees to our operations, we believe the presentation of equity earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate. Information by business segment, together with reconciliations to our Consolidated Balance Sheet totals, is presented in the following table:
Segment assets consist of property, plant and equipment, investments in unconsolidated affiliates, intangible assets and goodwill. The carrying values of such amounts are assigned to each segment based on each asset’s or investment’s principal operations and contribution to the gross operating margin of that particular segment. Since construction-in-progress (a component of property, plant and equipment) does not contribute to segment gross operating margin, such amounts are excluded from segment asset totals until the underlying assets are placed in service. Intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate. The remainder of our consolidated total assets, which consist primarily of working capital assets, are excluded from segment assets since these amounts are not attributable to one specific segment (e.g., cash). Supplemental Revenue and Expense Information The following table presents additional information regarding our consolidated revenues and costs and expenses for the years indicated:
Fluctuations in our product sales revenues and Major Customer Information Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. No single customer accounted for 10% or more of our consolidated revenues during the year ended December 31,
Note 11. Earnings Per Unit The following table presents our calculation of basic and diluted earnings per common unit for the years indicated:
Note 12. Business Combinations On February 17, 2022, an affiliate of Enterprise acquired all of the member interests in Navitas Midstream Partners, LLC (“Navitas Midstream”) for $3.2 billion in cash. We funded the cash consideration using proceeds from the issuance of short-term notes under EPO’s commercial paper program and cash on hand. Navitas Midstream's assets (the “Midland Basin System”) include approximately 1,750 miles of pipelines and over 1.0 Bcf/d of cryogenic natural gas processing capacity. The acquired business expands our natural gas processing and NGL businesses to the Midland Basin in West Texas. The acquisition of Navitas Midstream was accounted for under the acquisition method in accordance with ASC 805, Business Combinations. The preliminary allocation of purchase consideration was based upon the estimated fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in the acquisition. The preliminary allocation was made to major categories of assets and liabilities based on management’s best estimates and supported by an independent third-party analysis. We engaged an independent third party business valuation expert to assist us in estimating the fair values of the tangible and intangible assets of Navitas Midstream. The following table summarizes the final fair value allocation of assets acquired and liabilities assumed in the acquisition at February 17, 2022 (the effective date of the acquisition).
The contribution of this newly acquired business to our consolidated revenues and net income was not material during the year ended December 31, 2022. Additionally, acquisition related costs were not material during the year ended December 31, 2022. On a historical pro forma basis, our revenues, costs and expenses, operating income, net income attributable to common unitholders and earnings per unit for the years ended December 31, 2022 and 2021 would not have differed materially from those we actually reported had the acquisition been completed on January 1, 2021 rather than February 17, 2022. Note An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the years indicated:
The fair value of equity-classified awards is amortized to earnings over the requisite service or vesting period. Equity-classified awards are expected to result in the issuance of the Partnership’s common units upon vesting. The 2008 Enterprise Products Long-Term Incentive Plan (Fourth Amendment and Restatement)(referred to as the “2008 Plan”) is a plan under which any non-employee director, employee or consultants of EPCO, the Partnership or its affiliates providing services, directly or indirectly, for The maximum number of the Phantom Unit Awards Subject to customary forfeiture provisions, phantom unit awards allow recipients to acquire the Partnership’s common units once a defined vesting period expires (at no cost to the recipient apart from fulfilling required service and other conditions). We expect phantom units to result in the issuance of common units upon vesting; therefore, these grants are accounted for as equity-classified awards. Phantom unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire. The grant date fair value of a phantom unit award is based on the market price per unit of the Partnership’s common units on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period. The following table presents phantom unit award activity for the years indicated:
The 2008 Plan provides for the issuance of DERs in connection with phantom unit awards. A DER entitles the participant to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the participant and the cash distribution per common unit paid by the Partnership to its common unitholders. Cash payments made in connection with DERs are charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed. The following table presents supplemental information regarding phantom unit awards for the years indicated:
For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was Profits Interest Awards In On November 6, 2023, the partners of EPD IV and EPCO II amended their respective Employee In exchange for the contributions of the Partnership’s common units, EPCO Holdings was admitted as the Class A limited partner of each Employee Partnership. Also on the applicable contribution date, certain key EPCO employees were issued Class B limited partner interests (i.e., profits interest awards) and admitted as Class B limited partners of each Employee Partnership, all without any capital contribution by such employees. EPCO serves as the general partner of each Employee Partnership. Each quarter, the Employee Partnerships, as owners of the Partnership’s common units, receive a cash distribution from the Partnership as do the Partnership’s other common unitholders. The cash received by the Employee Partnership is first used to pay the Class A limited partner a cash distribution equal to the product of (i) the number of the Partnership’s common units owned by the Employee Partnership and (ii) the Class A Preference Return (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis as a distribution. Upon liquidation of an Employee Partnership, assets having a then current fair market value equal to the Class A limited partner’s capital base in such Employee Partnership will be distributed to the Class A limited partner. Any remaining assets of such Employee Partnership will be distributed to the Class B limited partners of such Employee Partnership as a residual profits interest, which represents the appreciation in value of the Employee Partnership’s assets since the date of EPCO Holdings’ contribution to it, as described above. Unless otherwise agreed to by EPCO and a majority in interest of the limited partners of each Employee Partnership, such Employee Partnership will terminate at the earliest to occur of (i) 30 days following its vesting date, (ii) a change of control or (iii) a dissolution of the Employee Partnership. Individually, each Class B limited partner interest is subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting, with customary exceptions for death, disability and certain retirements. The risk of forfeiture will also lapse upon certain change of control events. Forfeited individual Class B limited partner interests are allocated to the remaining Class B limited partners. The following table summarizes key elements of each Employee Partnership as of December 31,
The fair value of each Employee Partnership The following table summarizes the assumptions we used in applying a Black-Scholes option pricing model or Monte Carlo model, as applicable, to derive that portion of the estimated fair value of the profits interest awards (at either the grant date or modification date) for each Employee Partnership:
Compensation expense attributable to the profits interest awards is based on the estimated fair value of each award. A portion of the fair value of these equity-based awards is allocated to us under the ASA as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of the Employee Partnerships, including the value of any contributions of units made by EPCO Holdings. Note In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. Interest Rate Hedging Activities We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), treasury locks and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings. During the fourth quarter of 2023, we Forward-Starting Swaps Forward-starting swaps hedge the risk of an increase in underlying benchmark interest rates during the period of time between the inception date of the swap agreement and the future date of a debt issuance. Under the terms of the forward-starting swaps, we pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a fixed interest rate applied to a notional amount and receive from the counterparties an amount equal to a variable interest rate Commodity Hedging Activities The prices of natural gas, NGLs, crude oil, petrochemicals and refined products and power are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps. At December 31, The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of derivative instruments and related contracts. The objective of our natural gas processing hedging program is to hedge an amount of earnings associated with these activities. We achieve this objective by executing fixed-price sales for a portion of our expected equity The objective of our inventory hedging program is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of derivative instruments and related contracts. The objective of our commercial energy hedging program is to hedge anticipated future purchases of power for certain operations in Southeast Texas by locking in purchase prices through the use of derivative instruments and related contracts. The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31,
The carrying amount of our inventories subject to fair value hedges was Certain basis swaps Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:
Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated:
Derivative assets and liabilities recorded on our Consolidated Balance Sheets are presented on a gross basis and determined at the individual transaction level. This presentation method is applied regardless of whether the respective exchange clearing agreements, counterparty contracts or master netting agreements contain netting language often referred to as “rights of offset.” Although derivative amounts are presented on a gross basis, having rights of offset enable the settlement of a net as opposed to gross receivable or payable amount under a counterparty default or liquidation scenario. Cash is paid and received as collateral under certain agreements, particularly for those associated with exchange transactions. For any cash collateral payments or receipts, corresponding assets or liabilities are recorded to reflect the variation margin deposits or receipts with exchange clearing brokers and customers. These balances are also presented on a gross basis on our Consolidated Balance Sheets. The tabular presentation above provides a means for comparing the gross amount of derivative assets and liabilities, excluding associated accounts payable and receivable, to the net amount that would likely be receivable or payable under a default scenario based on the existence of rights of offset in the respective derivative agreements. Any cash collateral paid or received is reflected in these tables, but only to the extent that it represents variation margins. Any amounts associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from these tables. The following tables present the effect of our derivative instruments designated as fair value hedges on our Statements of Consolidated Operations for the years indicated:
The gain (loss) corresponding to the hedge ineffectiveness on the fair value hedges was negligible for all periods presented. The remaining gain (loss) for each period presented is primarily attributable to prompt-to-forward month price differentials that were excluded from the assessment of hedge effectiveness. The following tables present the effect of our derivative instruments designated as cash flow hedges on our Statements of Consolidated Operations and Statements of Consolidated Comprehensive Income for the years indicated:
Over the next twelve months, we expect to reclassify The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the years indicated:
The In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, unrealized mark-to-market gains (losses) included in gross operating margin
Fair Value Measurements The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy (see Note 2), the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment. The values for commodity derivatives are presented before and after the application of
In the aggregate, the fair value of our commodity hedging portfolios at December 31,
Financial assets and liabilities recorded on the balance sheet at December 31,
Other Fair Value Information The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was Note The following table summarizes our related party transactions for the years indicated:
The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated:
We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. Relationship with EPCO and Affiliates We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies. At December 31,
Of the total number of Partnership common units held by EPCO and its privately held affiliates, The Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates We lease office space from privately held affiliates of EPCO at rental rates that approximate market rates. EPCO ASA We have no employees. All of our administrative and operating functions are provided either by employees of EPCO (pursuant to the ASA) or by other service providers. We and our general partner are parties to the ASA. Under the ASA, EPCO provides us with the administrative and operating services deemed necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). Our operating costs and expenses include amounts paid to EPCO for the actual direct and indirect costs it incurs to operate our facilities, including the compensation of its employees. Likewise, our general and administrative costs include amounts paid to EPCO for management and other administrative services, including the compensation of its employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time with respect to the services provided to us by EPCO. The ASA allows us to participate as a named insured in EPCO’s overall insurance program, with the associated premiums and other costs being allocated to us. See Note The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated:
Since the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up is charged or subsidy is received), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. Relationships with Unconsolidated Affiliates Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. The following information summarizes significant related party transactions with our unconsolidated affiliates: For the years ended December 31, For the years ended December 31, We pay Promix for the transportation, storage and fractionation of NGLs. Expenses with Promix were For the years ended December 31, We perform management services for certain of our unconsolidated affiliates. We charged such affiliates Note Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in “qualifying income” (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31,
Income taxes are accounted for under the asset-and-liability method. Deferred We recognize the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. Accounting guidance provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. We did not rely on any uncertain tax positions in recording our income tax-related amounts during the years ended December 31, Tabular Disclosures Regarding Income Taxes Our federal, state and foreign income tax benefit (provision) is summarized below:
A reconciliation of the
Deferred income taxes are determined based on the temporary differences between the financial statement and income tax bases of assets and liabilities as measured by the enacted tax rates, which will be in effect when these differences reverse. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated:
Note Litigation As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the Partnership in litigation matters. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Based on a consideration of all relevant known facts and circumstances, we do not believe that the ultimate outcome of any currently pending litigation directed against us will have a material impact on our consolidated financial statements either individually at the claim level or in the aggregate. Commitments Under Equity Compensation Plans of EPCO In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense attributable to employees who perform management, administrative and operating functions for us. See Notes Contractual Obligations The following table summarizes our various contractual obligations at December 31, 2023. A description of each type of contractual obligation follows:
Scheduled Maturities of Debt We have long-term and short-term payment obligations under debt agreements. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the years indicated. See Note 7 for additional information regarding our consolidated debt obligations. Estimated Cash Interest Payments Our estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, Operating Lease Obligations We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year. Our significant lease agreements consist of (i) land held pursuant to property leases, (ii) the lease of underground storage caverns for natural gas, NGLs and ethylene, (iii) the lease of compressors and transportation equipment used in our operations and (iv) office space leased from affiliates of EPCO. These lease agreements have terms that range from 5 to 30 years. The agreements to lease office space from affiliates of EPCO and those relating to underground NGL storage caverns we lease from a third party include renewal options that could extend these contracts for up to an additional 20 years. The remainder of our significant lease agreements do not provide for additional renewal terms. Lease expense is charged to operating costs and expenses on a straight-line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. The following table presents information regarding operating leases where we are the lessee at December 31,
The following table disaggregates our total operating lease expense for the years indicated:
Fixed lease expense is charged to earnings on a straight-line basis over the contractual term, with any variable lease payments expensed as incurred. Short-term operating lease expense is expensed as incurred. Cash paid for operating lease liabilities recorded on our balance sheet was We do not have any significant operating or direct financing leases where we are the lessor. Our operating lease income for the years ended December 31, Purchase Obligations We define purchase obligations as agreements with remaining terms in excess of one year to purchase goods or services that are enforceable and legally binding (i.e., unconditional) on us that specify all significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transactions. We classify our unconditional purchase obligations into the following categories: Product purchase commitments – We have long-term product purchase obligations for natural gas, NGLs, crude oil, and petrochemicals and refined products with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table presents our estimated future payment obligations under these contracts based on the contractual price in each agreement at December 31, Service payment commitments – We have long-term commitments to pay service providers, including those attributable to obligations under firm pipeline transportation contracts. Payment obligations vary by contract, but generally represent a price per unit of volume multiplied by a firm transportation volume commitment. We have short-term payment obligations relating to our capital expenditures, including our share of the capital expenditures of unconsolidated affiliates. These commitments represent unconditional payment obligations for services to be rendered or products to be delivered in connection with capital projects. F-65 ENTERPRISE PRODUCTS PARTNERS L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Other Long-Term Liabilities The following table summarizes the components of “Other long-term liabilities” as presented on our Consolidated Balance Sheets at the dates indicated:
Note Nature of Operations We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, and petrochemical and refined products. As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services. In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions, public health emergencies and government regulations affecting prices and production levels. The natural gas, NGL and crude oil volumes currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time. To offset this natural decline, our facilities need access to production from newly discovered properties. Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons. A decrease in exploration and development activities in the regions where our facilities and other energy logistics assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows. Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted. We compete with other companies for such production on the basis of many factors, including, but not limited to, geographic proximity to the production, costs of connection, available capacity, rates and access to markets. Credit Risk We may incur credit risk to the extent counterparties do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, crude oil, and petrochemicals and refined products and under long-term contracts with minimum volume commitments or fixed demand charges. Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Further, adverse economic conditions in our industry, such as those experienced in connection with the COVID-19 pandemic in 2020, may increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings or small-scale companies. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk. The primary markets for our services are the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the U.S. We have a concentration of trade receivables due from independent and major integrated oil and gas companies and other pipelines and wholesalers operating in these markets. These concentrations may affect our overall credit risk in that these energy industry customers may be similarly affected by adverse changes in economic, regulatory or other factors. In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral for such transactions nor do we currently anticipate nonperformance by our material counterparties. Insurance Matters We participate as a named insured in EPCO’s insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material adverse impact on our financial position, results of operations and cash flows. In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of the Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to a fire). Some of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired assets. In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Consolidated Balance Sheets and presented as “Capital expenditures” on our Statements of Consolidated Cash Flows. Under our current insurance program, the standalone deductible for property damage claims is $30 million. We also have business interruption protection; however, such claims must involve physical damage and have a combined loss value in excess of $30 million and the period of interruption must exceed 60 days. With respect to named windstorm claims, the maximum amount of insurance coverage available to us for any single event is $200 million, after applying the appropriate deductibles. A named windstorm is a hurricane, typhoon, tropical storm or cyclone as declared by the U.S. National Weather Service. Note The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the years indicated:
We incurred liabilities for construction in progress that had not been paid at December 31, 2023, 2022 and 2021 The following table presents our cash proceeds from asset sales and other matters for the years indicated:
The following table presents net gains (losses) attributable to asset sales and related matters for the years indicated:
Note Issuance of $2.0 Billion of Senior Notes in January 2024 In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 (“Senior Notes HHH”) and (ii) $1.0 billion principal amount of senior notes due January 2034 (“Senior Notes III”). Net proceeds from this offering will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program). Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. Acquisition of Additionally, on February 16, 2024, an affiliate of Enterprise entered into a definitive agreement to acquire |