(State or Other Jurisdiction of Incorporation or Organization) |
(I.R.S. Employer Identification No.) |
(Address of Principal Executive Offices, including Zip Code) |
( |
(Registrant’s Telephone Number, including Area Code) |
Title of Each Class |
Trading Symbol(s) |
Name of Each Exchange On Which Registered |
Page |
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Number |
||
/d |
= |
per day |
MMBbls |
= |
million barrels |
BBtus |
= |
billion British thermal units |
MMBPD |
= |
million barrels per day |
Bcf |
= |
billion cubic feet |
MMBtus |
= |
million British thermal units |
BPD |
= |
barrels per day |
MMcf |
= |
million cubic feet |
MBPD |
= |
thousand barrels per day |
TBtus |
= |
trillion British thermal units |
• | natural gas gathering, treating, processing, transportation and storage; |
• | NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases, or “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 energy evolution and demand growth, including exports, for natural gas, NGLs, crude oil and petrochemical and refined products; |
• | maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary midstream energy assets; |
• | enhance the stability of our cash flows by investing in pipelines and other fee-based businesses; and |
• | share capital costs and risks through business ventures or alliances with strategic partners, including those that provide processing, throughput or feedstock volumes for growth capital projects or the purchase of such projects’ end products. |
• | 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 |
||||
Production |
Processing |
Capacity |
|||
Region |
Ownership |
Capacity |
of Plant |
||
Facility Name |
Location |
Served |
Interest |
(MMcf/d) (1) |
(MMcf/d) |
Meeker |
Colorado |
Piceance |
100.0% |
1,800 |
1,800 |
Pioneer |
Wyoming |
Green River |
100.0% |
1,100 |
1,100 |
Yoakum |
Texas |
Eagle Ford |
100.0% |
1,050 |
1,050 |
Pascagoula |
Mississippi |
Gulf of Mexico |
75.0% (2) |
750 |
1,000 |
Orla |
Texas |
Delaware |
100.0% |
900 |
900 |
Chaco |
New Mexico |
San Juan |
100.0% |
600 |
600 |
Neptune |
Louisiana |
Gulf of Mexico |
66.0% (3) |
430 |
650 |
Sea Robin |
Louisiana |
Gulf of Mexico |
54.1% (3) |
352 |
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 |
Shoup |
Texas |
Eagle Ford |
100.0% |
280 |
280 |
Armstrong |
Texas |
Eagle Ford |
100.0% |
250 |
250 |
Gilmore |
Texas |
Frio-Vicksburg |
100.0% |
250 |
250 |
San Martin |
Texas |
Eagle Ford |
100.0% |
200 |
200 |
South Eddy |
New Mexico |
Delaware |
100.0% |
200 |
200 |
Waha |
Texas |
Delaware |
100.0% |
150 |
150 |
Sonora |
Texas |
Strawn |
100.0% |
120 |
120 |
Venice |
Louisiana |
Gulf of Mexico |
13.1% (5) |
98 |
750 |
Indian Springs |
Texas |
Wilcox-Woodbine |
75.0% (3) |
90 |
120 |
Chaparral |
New Mexico |
Delaware |
100.0% |
45 |
45 |
Total |
9,615 |
11,065 |
(1) |
The approximate net gas processing 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) |
We own a 75% consolidated interest in the Pascagoula facility through our majority owned subsidiary, Pascagoula Gas Processing LLC. |
(3) |
We proportionately consolidate our undivided interests in these operating assets. |
(4) |
The Carthage processing complex consists of two natural gas processing plants: Panola and Bulldog. |
(5) |
Our 13.1% ownership in the Venice plant is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C. |
Pipeline |
|||
Ownership |
Length |
||
Description of Asset |
Location(s) |
Interest |
(Miles) |
Mid-America Pipeline System (1) |
Midwest and Western U.S. |
100.0% |
7,977 |
South Texas NGL Pipeline System |
Texas |
100.0% |
2,019 |
Dixie Pipeline (1) |
South and Southeastern U.S. |
100.0% |
1,307 |
ATEX (1) |
Texas to Midwest and Northeast U.S. |
100.0% |
1,192 |
Chaparral NGL System (1) |
Texas, New Mexico |
100.0% |
1,085 |
Louisiana Pipeline System (1) |
Louisiana |
100.0% |
877 |
Seminole NGL Pipeline (1) |
Texas |
100.0% |
869 |
Shin Oak NGL Pipeline |
Texas |
67.0% (3) |
664 |
Texas Express Pipeline (1) |
Texas |
35.0% (4) |
594 |
Skelly-Belvieu Pipeline (1) |
Texas, Oklahoma |
50.0% (5) |
572 |
Front Range Pipeline (1) |
Colorado, Oklahoma, Texas |
33.3% (6) |
451 |
Houston Ship Channel Pipeline System |
Texas |
100.0% |
304 |
Aegis Ethane Pipeline (1) |
Texas, Louisiana |
100.0% |
299 |
Panola Pipeline (1) |
Texas |
55.0% (7) |
253 |
Rio Grande Pipeline (1) |
Texas |
100.0% |
249 |
Lou-Tex NGL Pipeline (1) |
Texas, Louisiana |
100.0% |
206 |
Promix NGL Gathering System |
Louisiana |
50.0% (8) |
194 |
Texas Express Gathering System |
Texas |
45.0% (9) |
170 |
Tri-States NGL Pipeline (1) |
Alabama, Mississippi, Louisiana |
83.3% (10) |
168 |
Others (eight systems) (2) |
Various |
Various (11) |
459 |
Total |
19,909 |
(1) |
Interstate transportation services provided by these liquids pipelines, in whole or part, are regulated by federal governmental agencies. |
(2) |
Includes our Belle Rose and Wilprise pipelines located in the coastal regions of Louisiana; two pipelines located near Port Arthur in southeast Texas; our San Jacinto pipeline located in East Texas; our Permian NGL lateral pipelines located in West Texas; Leveret pipeline in West Texas and New Mexico; and a pipeline in Colorado associated with our Meeker facility. Transportation services provided by the Wilprise, Permian NGL and Leveret pipelines are regulated by federal governmental agencies. |
(3) |
We own a 67% consolidated interest in the Shin Oak NGL Pipeline through our majority owned subsidiary, Breviloba, LLC. |
(4) |
Our 35% ownership interest in the Texas Express Pipeline is held indirectly through our equity method investment in Texas Express Pipeline LLC. |
(5) |
Our 50% ownership interest in the Skelly-Belvieu Pipeline is held indirectly through our equity method investment in Skelly-Belvieu Pipeline Company, L.L.C. |
(6) |
Our 33.3% ownership interest in the Front Range Pipeline is held indirectly through our equity method investment in Front Range Pipeline LLC. |
(7) |
We own a 55% consolidated interest in the Panola Pipeline through our majority owned subsidiary, Panola Pipeline Company, LLC. |
(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) |
Our 45% ownership interest in the Texas Express Gathering System is held indirectly through our equity method investment in Texas Express Gathering LLC. |
(10) |
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. |
(11) |
We own a 74.7% consolidated interest in the 30-mile Wilprise pipeline through our majority owned subsidiary, Wilprise Pipeline Company, L.L.C. We proportionately consolidate our 50% undivided interest in a 45-mile segment of the Port Arthur pipelines. The remainder of these NGL pipelines are wholly owned. |
• | The Mid-America Pipeline System is an NGL pipeline system consisting of the 3,119-mile Rocky Mountain pipeline, the 2,138-mile Conway North pipeline, the 632-mile Ethane-Propane (“EP”) Mix pipeline, and the 2,088-mile Conway South pipeline. The Rocky Mountain pipeline transports mixed NGLs from production fields located in the Rocky Mountain Overthrust and San Juan Basin to the Hobbs NGL hub located on the Texas-New Mexico border. The Conway North segment links the NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest. NGL hubs, such as those at Mont Belvieu, Hobbs and Conway, provide buyers and sellers with a centralized location for the storage and pricing of products, while also providing connections to intrastate and/or interstate pipelines. The EP Mix segment transports EP mix from the Conway hub to petrochemical plants in Iowa and Illinois. The Conway South pipeline connects the Conway hub with Kansas refineries and provides bi-directional transportation of NGLs between the Conway and Hobbs hubs. At the Hobbs NGL hub, the Mid-America Pipeline System interconnects with our Seminole NGL Pipeline and Hobbs NGL fractionation and storage facility. The Mid-America Pipeline System is also connected to 18 non-regulated NGL terminals that we own and operate. |
• | The South Texas NGL Pipeline System is a network of NGL gathering and transportation pipelines located in South Texas that gather and transport mixed NGLs from natural gas processing facilities (owned by either us or third parties) to our NGL fractionators located in South Texas and at the Mont Belvieu hub 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 Mont Belvieu storage complex. The South Texas NGL Pipeline System extends our ethane header system from the Mont Belvieu hub 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 Mont Belvieu 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 the Mont Belvieu hub. This system consists of the 906-mile Chaparral pipeline and the 179-mile Quanah pipeline. Interstate and intrastate transportation services provided by the Chaparral pipeline are regulated; however, transportation services provided by the Quanah pipeline are not. |
• | The Louisiana Pipeline System is a network of NGL pipelines 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 NGL fractionation complex located in and near Mont Belvieu. 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 NGL fractionation and storage complex located at the Mont Belvieu hub. |
• | The Texas Express Pipeline extends from Skellytown, Texas to our NGL fractionation and storage complex located in and near Mont Belvieu. 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 Mont Belvieu. 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 Mont Belvieu area assets to our marine terminals on the Houston Ship Channel and to area petrochemical plants, refineries and other pipelines. |
• | The Aegis Ethane Pipeline (“Aegis”) delivers purity ethane to petrochemical facilities located along the southeast Texas and Louisiana Gulf Coast. Aegis, when combined with 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 Panola Pipeline transports mixed NGLs from injection points near Carthage, Texas to the Mont Belvieu hub 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 Lou-Tex NGL Pipeline transports mixed NGLs, purity NGL products and refinery grade propylene (“RGP”) between the Louisiana and Texas markets. |
Net Plant |
Total Plant |
|||
Ownership |
Capacity |
Capacity |
||
Description of Asset |
Location |
Interest |
(MBPD) (1) |
(MBPD) |
NGL fractionation facilities: |
||||
Mont Belvieu-area: |
||||
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 |
Total Mont Belvieu-area |
962 |
1,060 |
||
Shoup and Armstrong |
Texas |
100.0% |
93 |
93 |
Hobbs |
Texas |
100.0% |
75 |
75 |
Norco |
Louisiana |
100.0% |
75 |
75 |
Promix |
Louisiana |
50.0% (4) |
73 |
145 |
Tebone |
Louisiana |
100.0% |
30 |
30 |
Baton Rouge |
Louisiana |
32.2% (5) |
19 |
60 |
Total |
1,327 |
1,538 |
(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) |
We proportionately consolidate a 75% undivided interest in these fractionators. |
(3) |
We own a 75% consolidated equity interest in NGL fractionators VII and VIII through our majority owned subsidiary, Enterprise EF78 LLC. |
(4) |
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. |
(5) |
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 Mont Belvieu, Texas and surrounding areas of 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 Mont Belvieu-area NGL fractionators are connected to our network of NGL supply and distribution pipelines, approximately 130 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 the Mont Belvieu hub using our South Texas NGL Pipeline System. |
• | The Hobbs NGL fractionator serves NGL producers in West Texas, New Mexico and Colorado. 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 both the Mont Belvieu and Conway hubs. |
• | The Norco NGL fractionator receives mixed NGLs from refineries and natural gas processing facilities located in southern Louisiana and along the Mississippi and Alabama Gulf Coast, including our Pascagoula and Venice facilities. |
Net Usable |
|||
Storage |
|||
Ownership |
Capacity |
||
Description of Asset |
Location |
Interest |
(MMBbls) (1) |
Mont Belvieu storage complex |
Texas |
100.0% |
129.8 |
Breaux Bridge, Anse La Butte and Sorrento (2) |
Louisiana |
100.0% |
12.7 |
Almeda and Markham (3) |
Texas |
Leased |
12.4 |
Petal (4) |
Mississippi |
100.0% |
5.4 |
Hutchinson (5) |
Kansas |
100.0% |
4.0 |
Others (6) |
Various |
Various |
14.3 |
Total |
178.6 |
(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 Louisiana Pipeline System. |
(3) |
These storage facilities are used in connection with our South Texas NGL 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 seven deep-water ship docks, a barge dock and a lay berth dock. The terminal can accommodate vessels with up to a 45 foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel. We believe that our location on the Houston Ship Channel enables us to handle larger vessels than our competitors because our waterfront has fewer draft and beam (width) restrictions. The size and structure of our waterfront allows us to receive and unload products for our customers and provide terminaling services. |
• | The Morgan’s Point Ethane Export Terminal, located on the Houston Ship Channel, has a nameplate loading capacity of approximately 10,000 barrels per hour of fully refrigerated ethane and is the largest of its kind in the world. The terminal supports domestic production of U.S. ethane from shale plays by providing the global petrochemical industry with access to a low-cost feedstock option and opportunities for supply diversification. Ethane volumes handled by the terminal are sourced from our Mont Belvieu-area NGL fractionators and storage complex. Ethane loading volumes at the terminal averaged 134 MBPD, 143 MBPD and 146 MBPD during the years ended December 31, 2020, 2019 and 2018, respectively. |
Operational |
||||
Our |
Storage |
Pipeline |
||
Ownership |
Capacity |
Length |
||
Description of Asset |
Location(s) |
Interest |
(MMBbls) (2) |
(Miles) |
Midland-to-ECHO System: |
||||
Midland-to-ECHO 1 pipeline |
Texas |
80.0% (3) |
4.0 |
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: |
4.0 |
1,383 |
||
Seaway Pipeline (1) |
Texas, Oklahoma |
50.0% (5) |
9.8 |
1,273 |
West Texas System (1) |
Texas, New Mexico |
100.0% |
1.3 |
1,078 |
South Texas Crude Oil Pipeline System |
Texas |
100.0% |
5.1 |
633 |
Basin Pipeline (1) |
Texas, New Mexico, Oklahoma |
13.0% (6) |
6.0 |
618 |
EFS Midstream System |
Texas |
100.0% |
0.3 |
525 |
Eagle Ford Crude Oil Pipeline System |
Texas |
50.0% (7) |
4.5 |
390 |
Total |
31.0 |
5,900 |
(1) |
Transportation services provided by these liquids pipelines are regulated, in whole or part, by federal governmental agencies. |
(2) |
Operational storage capacity amounts presented on a gross basis. |
(3) |
The Midland-to-Sealy section of the Midland-to-ECHO 1 pipeline is owned by Whitethorn Pipeline Company LLC, in which we own an 80% consolidated interest. |
(4) |
We proportionately consolidate our 29% undivided interest in the Midland-to-Webster pipeline, which we refer to as the Midland-to-ECHO 3 pipeline. |
(5) |
Our 50% ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Holdings LLC (“Seaway”). |
(6) |
We proportionately consolidate our 13% undivided interest in the Basin Pipeline. |
(7) |
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. 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 South Texas Crude Oil Pipeline System transports crude oil and condensate originating in South Texas to customers in the Houston area. This system includes storage terminal assets located at 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 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 525 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 Eagle Ford Crude Oil Pipeline System transports crude oil and condensate for producers in South Texas. The system, which is effectively looped and has a capacity to transport over 600 MBPD of light and medium grades of crude oil, consists of 390 miles of crude oil and condensate pipelines originating in Gardendale, Texas and extending to Corpus Christi, Texas. The system interconnects with our South Texas Crude Oil Pipeline System in Wilson County, Texas and our Corpus Christi marine terminal. |
Number of |
Net Storage |
|||
Ownership |
Above-Ground |
Capacity |
||
Description of Asset |
Location(s) |
Interest |
Tanks in Service |
(MMBbls) |
EHT (crude oil) |
Texas |
100.0% |
81 |
23.4 |
ECHO (1) |
Texas |
100.0% |
14 |
5.9 |
Beaumont Marine West |
Texas |
100.0% |
12 |
4.2 |
Cushing |
Oklahoma |
100.0% |
19 |
3.3 |
Midland (2) |
Texas |
100.0% |
9 |
2.7 |
Corpus Christi |
Texas |
50.0% (3) |
4 |
0.7 |
Total |
139 |
40.2 |
(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. |
• | Our EHT marine terminal located on the Houston Ship Channel includes export assets capable of loading up to 2.0 MMBPD, or 62 MMBbls per month, of crude oil. The crude oil terminal at EHT represents one of the largest such facilities on the Gulf Coast. As noted previously, EHT can accommodate vessels with up to a 45-foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel. |
• | The ECHO terminal is located in Houston, Texas and provides storage customers with access to major refineries located in the Houston, Texas City and Beaumont/Port Arthur areas. ECHO also has connections to marine terminals, including EHT, that provide access to any refinery on the U.S. Gulf Coast and international markets. |
• | The Beaumont Marine West terminal is located on the Neches River near Beaumont, Texas. This terminal includes three deep-water docks and one barge dock that facilitate the exporting and importing of crude oil and related products. |
• | The Cushing terminal is located at the Cushing hub in Oklahoma and provides crude oil storage, pumpover and trade documentation services. This terminal is one of the origination points for our Seaway Pipeline. |
• | The Midland terminal provides crude oil storage, pumpover and trade documentation services. The Midland terminal is the origination point for our Midland-to-ECHO pipelines. |
• | The Corpus Christi terminal, located in Corpus Christi, Texas, is capable of loading ocean-going vessels with either crude oil or condensate. The terminal includes one deep-water ship dock and serves Eagle Ford Shale and Permian Basin producers through a connection with our Eagle Ford Crude Oil Pipeline System. |
Net Capacity (1) |
||||||
Pipeline |
Pipeline |
Natural Gas |
Usable |
|||
Ownership |
Length |
Capacity |
Treating |
Storage |
||
Description of Asset |
Location(s) |
Interest |
(Miles) |
(MMcf/d) |
(MMcf/d) |
(Bcf) |
Texas Intrastate System (2) |
Texas |
Various (5) |
6,893 |
7,345 |
– |
12.9 |
Acadian Gas System (2) |
Louisiana |
100.0% (6) |
1,307 |
3,100 |
– |
1.3 |
Jonah Gathering System |
Wyoming |
100.0% |
776 |
2,360 |
– |
– |
Piceance Basin Gathering System |
Colorado |
100.0% |
191 |
1,800 |
– |
– |
San Juan Gathering System |
New Mexico, Colorado |
100.0% |
6,117 |
1,750 |
420 |
– |
Permian Basin Gathering System |
Texas, New Mexico |
100.0% |
1,722 |
1,575 |
150 |
– |
White River Hub (3) |
Colorado |
50.0% (7) |
10 |
1,500 |
– |
– |
Haynesville Gathering System |
Louisiana, Texas |
100.0% |
360 |
1,300 |
810 |
– |
BTA Gathering System (4) |
Texas |
100.0% (8) |
788 |
925 |
840 |
– |
Indian Springs Gathering System (4) |
Texas |
80.0% (9) |
145 |
160 |
– |
– |
Delmita Gathering System |
Texas |
100.0% |
203 |
145 |
– |
– |
South Texas Gathering System |
Texas |
100.0% |
517 |
143 |
220 |
– |
Old Ocean Pipeline |
Texas |
50.0% (10) |
240 |
80 |
– |
– |
Big Thicket Gathering System |
Texas |
100.0% |
250 |
60 |
– |
– |
Central Treating Facility |
Colorado |
100.0% |
– |
– |
200 |
– |
Total |
19,519 |
22,243 |
2,640 |
14.2 |
(1) |
Net capacity amounts are based on our ownership interest or contractual right-of-use. |
(2) |
Transportation services provided by these pipeline systems, in whole or part, are regulated by both federal and state governmental agencies. |
(3) |
Services provided by the White River Hub are regulated by federal governmental agencies. |
(4) |
Transportation services provided by these systems are regulated in part by state governmental agencies. |
(5) |
We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,471 miles of the Texas Intrastate System. The Texas Intrastate System also includes our Wilson natural gas storage facility, which consists of a network of leased and owned underground salt dome storage caverns located in Wharton County, Texas with an aggregate 12.9 Bcf of usable storage capacity. Four of these caverns, comprising 6.9 Bcf of usable capacity, are held under an operating lease. The remainder of our Texas Intrastate System is wholly owned. |
(6) |
The Acadian Gas System includes a leased 1.3 Bcf underground salt dome natural gas storage cavern located at Napoleonville, Louisiana. |
(7) |
Our 50% ownership interest in White River Hub is held indirectly through our equity method investment in White River Hub, LLC. |
(8) |
This system includes approximately 52 miles of pipeline held under an operating lease. |
(9) |
We proportionately consolidate our 80% undivided interest in the Indian Springs Gathering System. |
(10) |
Our 50% ownership interest in the Old Ocean Pipeline is held indirectly through our equity method investment in Old Ocean Pipeline, LLC. |
• | The Texas Intrastate System is comprised of the 6,276-mile Enterprise Texas pipeline system and the 617-mile Channel pipeline system. The Texas Intrastate System gathers, transports and stores natural gas from supply basins in Texas including the Permian Basin and Eagle Ford and Barnett Shales for delivery to local gas distribution companies, electric utility plants and industrial and municipal consumers. The system is also connected to regional natural gas processing facilities and other intrastate and interstate pipelines. The Texas Intrastate System serves a number of commercial markets in Texas, including Corpus Christi, San Antonio/Austin, Beaumont/Orange and Houston, including the Houston Ship Channel industrial market. |
• | The Acadian Gas System transports, stores and markets natural gas in Louisiana. The Acadian Gas System is comprised of the 582-mile Cypress pipeline, 424-mile Acadian pipeline, 275-mile Haynesville Extension pipeline and 26-mile Enterprise Pelican pipeline. The Acadian Gas System links natural gas supplies from Louisiana (e.g., from the Haynesville Shale supply basin) and offshore Gulf of Mexico developments with local gas distribution companies, electric utility plants and industrial customers located primarily in the Baton Rouge/New Orleans/Mississippi River corridor. |
• | 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 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 further processing prior to being transported on interstate pipelines. |
• | The Permian Basin Gathering System is comprised of the 1,051-mile Carlsbad pipeline system, the 614-mile Waha pipeline system, the 34-mile Orla pipeline system and the 23-mile Mentone pipeline system. The Permian Basin Gathering System gathers natural gas from the Permian Basin for delivery to regional natural gas processing facilities, including our Chaparral, South Eddy, Waha, Mentone and Orla plants, and delivers residue and treated natural gas into our Texas Intrastate System and third-party pipelines. |
• | The White River Hub is a natural gas hub facility serving producers in the Piceance Basin. The facility enables producers to access six interstate natural gas pipelines and has a gross throughput capacity of 3 Bcf/d of natural gas. |
• | The Haynesville Gathering System consists of the 217-mile State Line gathering system, the 73-mile Southeast Mansfield gathering system, and the 70-mile Southeast Stanley gathering system. The Haynesville Gathering System gathers and treats natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas for delivery to regional markets, including (through an interconnect with the Haynesville Extension pipeline) markets served by our Acadian Gas System. |
• | 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 Indian Springs Gathering System, along with the Big Thicket Gathering System, gather natural gas from the Woodbine, Wilcox and Yegua production areas in East Texas. |
• | The Delmita Gathering System gathers natural gas from the Frio-Vicksburg formation in South Texas for delivery to our South Texas natural gas processing facilities. |
• | The South Texas Gathering System gathers natural gas from the Olmos and Wilcox formations for delivery to our South Texas natural gas processing facilities. |
• | The Old Ocean Pipeline transports natural gas from an injection point on our Texas Intrastate System near Maypearl, Texas for delivery to a pipeline interconnect at Sweeny, Texas. A third party serves as operator of the pipeline, which has a gross natural gas transportation capacity of 160 MMcf/d and entered full service in January 2019. |
• | 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 gas plant for further processing. |
• | propylene production facilities, which include propylene fractionation units and a PDH facility, and related pipelines and marketing activities; |
• | butane isomerization complex and related deisobutanizer (“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 |
||
Ownership |
Capacity |
Capacity |
||
Description of Asset |
Location |
Interest |
(MBPD) |
(MBPD) |
Propylene fractionation facilities: |
||||
Mont Belvieu (six units) |
Texas |
Various (1) |
80 |
93 |
BRPC (one unit) |
Louisiana |
30.0% (2) |
7 |
23 |
Total |
87 |
116 |
||
PDH facility: |
||||
PDH 1 |
Texas |
100.0% |
25 |
25 |
(1) |
We proportionately consolidate a 66.7% undivided interest in three of the propylene splitters, which have an aggregate 38 MBPD of total plant capacity. The remaining three propylene fractionation units are wholly owned. |
(2) |
Our 30% ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC (“BRPC”). |
Ownership |
Length |
||
Description of Asset |
Location(s) |
Interest |
(Miles) |
Lou-Tex Propylene Pipeline |
Texas, Louisiana |
100.0% |
267 |
North Dean Pipeline System |
Texas |
100.0% |
189 |
Texas City RGP Gathering System |
Texas |
100.0% |
157 |
Propylene Splitter PGP Distribution System |
Texas |
100.0% |
92 |
Louisiana RGP Gathering System |
Louisiana |
100.0% |
63 |
Lake Charles PGP Pipeline |
Texas, Louisiana |
50.0% (1) |
27 |
La Porte PGP Pipeline |
Texas |
80.0% (2) |
20 |
Sabine Pipeline |
Texas, Louisiana |
100.0% |
15 |
Total |
830 |
(1) |
We proportionately consolidate our 50% undivided interest in the Lake Charles PGP Pipeline. |
(2) |
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, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Refined products transportation (MBPD) |
419 |
407 |
456 |
|||||||||
Petrochemical transportation (MBPD) |
156 |
126 |
148 |
|||||||||
NGL transportation (MBPD) |
55 |
63 |
71 |
• | Our operations along the Gulf Coast, including those at our Mont Belvieu 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 plants 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 impacts from the COVID-19 pandemic and certain developments in the global oil markets have had, and may continue to 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 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, 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, our maintenance or repair costs may increase in the future. |
• | 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 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”) 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. |
• | 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 for tax years beginning after December 31, 2017, 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 or materials, accidents, weather conditions or an inability to obtain necessary permits; |
• | we will not receive any material increase in operating cash flows until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged; |
• | we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize; |
• | since we are not engaged in the exploration for and development of 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 2020 |
– |
$ |
– |
– |
$ |
1,745,312 |
||||||||||
November 2020 |
– |
$ |
– |
– |
$ |
1,745,312 |
||||||||||
December 2020 |
636,071 |
$ |
19.66 |
636,071 |
$ |
1,732,808 |
||||||||||
Vesting of phantom unit awards: |
||||||||||||||||
November 2020 (2) |
20,759 |
$ |
16.63 |
n/a |
n/a |
(1) |
In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of our common units. Common units repurchased under this program during 2020 were cancelled immediately upon acquisition. |
(2) |
Of the 83,609 phantom unit awards that vested in November 2020 and converted to common units, 20,759 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition. |
/d |
= |
per day |
MMBbls |
= |
million barrels |
BBtus |
= |
billion British thermal units |
MMBPD |
= |
million barrels per day |
Bcf |
= |
billion cubic feet |
MMBtus |
= |
million British thermal units |
BPD |
= |
barrels per day |
MMcf |
= |
million cubic feet |
MBPD |
= |
thousand barrels per day |
TBtus |
= |
trillion British thermal units |
• | natural gas gathering, treating, processing, transportation and storage; |
• | NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases, or “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. |
• | At December 31, 2020, we had $6.06 billion of consolidated liquidity, which was comprised of $5.0 billion of available borrowing capacity under EPO’s revolving credit facilities and $1.06 billion of unrestricted cash on hand. Our liquidity is supported by investment grade credit ratings on EPO’s long-term senior unsecured debt of BBB+, Baa1 and BBB+ from Standard and Poors, Moody’s and Fitch, respectively. |
• | EPO successfully issued $4.25 billion in principal amount of senior notes in 2020. Based on current conditions, we believe that we will have sufficient liquidity and/or access to debt capital markets to fund the remaining principal amount of senior notes maturing through 2021. |
• | In light of the current downturn in the domestic energy industry, we reevaluated our planned capital investments. Based on information currently available, we expect our total capital investments for 2021, net of contributions from joint venture partners, to approximate $2.1 billion, which reflects growth capital investments of $1.6 billion and sustaining capital expenditures of $440 million. In addition, we currently expect our growth capital investments in 2022 and 2023 for sanctioned projects to approximate $800 million and $400 million, respectively. These amounts do not include capital investments associated with our proposed deepwater offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to governmental approvals. We currently anticipate receiving approval for SPOT as early as the third quarter of 2021; however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision. |
• | We continue to optimize our assets to provide incremental services to customers and to respond to market opportunities. As prices for certain NGLs, crude oil and refined products fell in 2020 due to collapsing demand for refined products as a result of the pandemic, our storage services provided valuable flexibility for our customers. In addition, our earnings from marketing activities in 2020 benefited from using uncontracted storage capacity to capture contango opportunities in NGLs, crude oil and refined products. |
• | Across all of our assets, we have contracted with a large number of quality customers in order to achieve customer diversification. In 2020, our top 200 largest customers represented 95.3% of consolidated revenues. Based on their respective year-end 2020 debt ratings, 81.4% of our top 200 customers were either investment grade rated or backed by letters of credit. Additionally, only 8.1% of our top 200 customer revenues were attributable to sub-investment grade or non-rated upstream producers. |
Polymer |
Refinery |
Indicative Gas |
|||||||
Natural |
Normal |
Natural |
Grade |
Grade |
Processing |
||||
Gas, |
Ethane, |
Propane, |
Butane, |
Isobutane, |
Gasoline, |
Propylene, |
Propylene, |
Gross Spread |
|
$/MMBtu |
$/gallon |
$/gallon |
$/gallon |
$/gallon |
$/gallon |
$/pound |
$/pound |
$/gallon |
|
(1) |
(2) |
(2) |
(2) |
(2) |
(2) |
(3) |
(3) |
(4) |
|
2019 by quarter: |
|||||||||
1st Quarter |
$3.15 |
$0.30 |
$0.67 |
$0.82 |
$0.85 |
$1.16 |
$0.38 |
$0.24 |
$0.31 |
2nd Quarter |
$2.64 |
$0.21 |
$0.55 |
$0.63 |
$0.65 |
$1.21 |
$0.37 |
$0.24 |
$0.25 |
3rd Quarter |
$2.23 |
$0.17 |
$0.44 |
$0.51 |
$0.66 |
$1.06 |
$0.38 |
$0.23 |
$0.21 |
4th Quarter |
$2.50 |
$0.19 |
$0.50 |
$0.68 |
$0.82 |
$1.20 |
$0.35 |
$0.21 |
$0.25 |
2019 Averages |
$2.63 |
$0.22 |
$0.54 |
$0.66 |
$0.75 |
$1.16 |
$0.37 |
$0.23 |
$0.26 |
2020 by quarter: |
|||||||||
1st Quarter |
$1.95 |
$0.14 |
$0.37 |
$0.57 |
$0.63 |
$0.93 |
$0.31 |
$0.18 |
$0.19 |
2nd Quarter |
$1.71 |
$0.19 |
$0.41 |
$0.43 |
$0.44 |
$0.41 |
$0.26 |
$0.11 |
$0.17 |
3rd Quarter |
$1.98 |
$0.22 |
$0.50 |
$0.58 |
$0.60 |
$0.80 |
$0.35 |
$0.17 |
$0.25 |
4th Quarter |
$2.67 |
$0.21 |
$0.57 |
$0.76 |
$0.68 |
$0.92 |
$0.41 |
$0.24 |
$0.22 |
2020 Averages |
$2.08 |
$0.19 |
$0.46 |
$0.59 |
$0.59 |
$0.77 |
$0.33 |
$0.18 |
$0.21 |
(1) |
Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of McGraw Hill Financial, Inc. |
(2) |
NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service. |
(3) |
Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Chemical, a division of IHS Inc. (“IHS Chemical”). Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS Chemical. |
(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 at Mont Belvieu, 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 determined by regional pricing and extraction dynamics. |
WTI |
Midland |
Houston |
LLS |
|
Crude Oil, |
Crude Oil, |
Crude Oil |
Crude Oil, |
|
$/barrel |
$/barrel |
$/barrel |
$/barrel |
|
(1) |
(2) |
(2) |
(3) |
|
2019 by quarter: |
||||
1st Quarter |
$54.90 |
$53.70 |
$61.19 |
$62.35 |
2nd Quarter |
$59.81 |
$57.62 |
$66.47 |
$67.07 |
3rd Quarter |
$56.45 |
$56.12 |
$59.75 |
$60.64 |
4th Quarter |
$56.96 |
$57.80 |
$60.04 |
$60.76 |
2019 Averages |
$57.03 |
$56.31 |
$61.86 |
$62.71 |
2020 by quarter: |
||||
1st Quarter |
$46.17 |
$45.51 |
$47.81 |
$48.15 |
2nd Quarter |
$27.85 |
$28.22 |
$29.68 |
$30.12 |
3rd Quarter |
$40.93 |
$41.05 |
$41.77 |
$42.47 |
4th Quarter |
$42.66 |
$43.07 |
$43.63 |
$44.08 |
2020 Averages |
$39.40 |
$39.46 |
$40.72 |
$41.21 |
(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, |
||||||||
2020 |
2019 |
|||||||
Revenues |
$ |
27,199.7 |
$ |
32,789.2 |
||||
Costs and expenses: |
||||||||
Operating costs and expenses: |
||||||||
Cost of sales |
16,723.2 |
22,065.8 |
||||||
Other operating costs and expenses |
2,800.2 |
3,020.7 |
||||||
Depreciation, amortization and accretion expenses |
1,961.5 |
1,848.3 |
||||||
Net gains attributable to asset sales |
(4.4 |
) |
(5.7 |
) |
||||
Asset impairment and related charges |
890.6 |
132.7 |
||||||
Total operating costs and expenses |
22,371.1 |
27,061.8 |
||||||
General and administrative costs |
219.6 |
211.7 |
||||||
Total costs and expenses |
22,590.7 |
27,273.5 |
||||||
Equity in income of unconsolidated affiliates |
426.1 |
563.0 |
||||||
Operating income |
5,035.1 |
6,078.7 |
||||||
Interest expense |
(1,287.4 |
) |
(1,243.0 |
) |
||||
Change in fair value of Liquidity Option |
(2.3 |
) |
(119.6 |
) |
||||
Other, net |
16.0 |
16.6 |
||||||
Benefit from (provision for) income taxes |
124.3 |
(45.6 |
) |
|||||
Net income |
3,885.7 |
4,687.1 |
||||||
Net income attributable to noncontrolling interests |
(110.1 |
) |
(95.8 |
) |
||||
Net income attributable to preferred units |
(0.9 |
) |
– |
|||||
Net income attributable to common unitholders |
$ |
3,774.7 |
$ |
4,591.3 |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
NGL Pipelines & Services: |
||||||||
Sales of NGLs and related products |
$ |
8,970.7 |
$ |
10,934.3 |
||||
Midstream services |
2,206.5 |
2,536.4 |
||||||
Total |
11,177.2 |
13,470.7 |
||||||
Crude Oil Pipelines & Services: |
||||||||
Sales of crude oil |
5,410.8 |
9,007.8 |
||||||
Midstream services |
1,278.2 |
1,279.5 |
||||||
Total |
6,689.0 |
10,287.3 |
||||||
Natural Gas Pipelines & Services: |
||||||||
Sales of natural gas |
1,530.5 |
2,075.4 |
||||||
Midstream services |
1,022.6 |
1,094.0 |
||||||
Total |
2,553.1 |
3,169.4 |
||||||
Petrochemical & Refined Products Services: |
||||||||
Sales of petrochemicals and refined products |
5,942.6 |
4,985.2 |
||||||
Midstream services |
837.8 |
876.6 |
||||||
Total |
6,780.4 |
5,861.8 |
||||||
Total consolidated revenues |
$ |
27,199.7 |
$ |
32,789.2 |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Interest charged on debt principal outstanding |
$ |
1,330.6 |
$ |
1,251.6 |
||||
Impact of interest rate hedging program, including related amortization (1) |
39.3 |
107.4 |
||||||
Interest costs capitalized in connection with construction projects (2) |
(115.0 |
) |
(143.8 |
) |
||||
Other (3) |
32.5 |
27.8 |
||||||
Total |
$ |
1,287.4 |
$ |
1,243.0 |
(1) |
Amount presented for the year ended December 31, 2019 reflects an unrealized, mark-to-market loss of $94.9 million recognized in September 2019 in connection with the exercise of swaptions. Due to declining interest rates, the counterparties to the swaptions exercised their right to put us into ten forward-starting swaps in September 2019 having an aggregate notional value of $1.0 billion. Since the swaptions were not designated as hedging instruments and were subject to mark-to-market accounting, we incurred an unrealized, mark-to-market loss at inception of the forward-starting swaps that is reflected as an increase in interest expense in 2019. The ten forward-starting swaps resulting from the swaption exercise were designated as hedging instruments and qualified for cash flow hedge accounting. |
(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. |
(3) |
Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs. |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Deferred tax benefit attributable to OTA |
$ |
155.3 |
||||||
Texas Margin Tax |
(32.1 |
) |
$ |
(44.2 |
) |
|||
Other |
1.1 |
(1.4 |
) |
|||||
Benefit from (provision for) income taxes |
$ |
124.3 |
$ |
(45.6 |
) |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Gross operating margin by segment: |
||||||||
NGL Pipelines & Services |
$ |
4,182.4 |
$ |
4,069.8 |
||||
Crude Oil Pipelines & Services |
1,997.3 |
2,087.8 |
||||||
Natural Gas Pipelines & Services |
926.6 |
1,062.6 |
||||||
Petrochemical & Refined Products Services |
1,081.8 |
1,069.6 |
||||||
Total segment gross operating margin (1) |
8,188.1 |
8,289.8 |
||||||
Net adjustment for shipper make-up rights |
(85.7 |
) |
(24.1 |
) |
||||
Total gross operating margin (non-GAAP) |
$ |
8,102.4 |
$ |
8,265.7 |
(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, |
||||||||
2020 |
2019 |
|||||||
Operating income |
$ |
5,035.1 |
$ |
6,078.7 |
||||
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 |
1,961.5 |
1,848.3 |
||||||
Asset impairment and related charges in operating costs and expenses |
890.6 |
132.7 |
||||||
Net gains attributable to asset sales in operating costs and expenses |
(4.4 |
) |
(5.7 |
) |
||||
General and administrative costs |
219.6 |
211.7 |
||||||
Total gross operating margin (non-GAAP) |
$ |
8,102.4 |
$ |
8,265.7 |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Segment gross operating margin: |
||||||||
Natural gas processing and related NGL marketing activities |
$ |
997.5 |
$ |
1,159.7 |
||||
NGL pipelines, storage and terminals |
2,524.1 |
2,402.2 |
||||||
NGL fractionation |
660.8 |
507.9 |
||||||
Total |
$ |
4,182.4 |
$ |
4,069.8 |
||||
Selected volumetric data: |
||||||||
NGL pipeline transportation volumes (MBPD) |
3,589 |
3,615 |
||||||
NGL marine terminal volumes (MBPD) |
722 |
626 |
||||||
NGL fractionation volumes (MBPD) |
1,359 |
1,017 |
||||||
Equity NGL production volumes (MBPD) (1) |
151 |
144 |
||||||
Fee-based natural gas processing volumes (MMcf/d) (2, 3) |
4,285 |
4,738 |
(1) |
Represents the NGL volumes we earn and take title to in connection with our processing activities. |
(2) |
Volumes reported correspond to the revenue streams earned by our 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, |
||||||||
2020 |
2019 |
|||||||
Segment gross operating margin: |
||||||||
Midland-to-ECHO System: |
||||||||
Midland-to-ECHO System and related business activities, excluding associated non-cash mark-to-market results |
$ |
359.5 |
$ |
463.0 |
||||
Midland-to-ECHO 1 non-cash mark-to-market gains (losses) |
(0.3 |
) |
88.4 |
|||||
Total Midland-to-ECHO System |
359.2 |
551.4 |
||||||
Other crude oil pipelines, terminals and related marketing results |
1,638.1 |
1,536.4 |
||||||
Total |
$ |
1,997.3 |
$ |
2,087.8 |
||||
Selected volumetric data: (1) |
||||||||
Crude oil pipeline transportation volumes (MBPD) |
2,166 |
2,304 |
||||||
Crude oil marine terminal volumes (MBPD) |
724 |
964 |
(1) |
In general, segment volumes for the year ended December 31, 2020 were adversely impacted by the reduction in upstream crude oil production activities caused by the COVID-19 pandemic and crude oil price shock. |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Segment gross operating margin |
$ |
926.6 |
$ |
1,062.6 |
||||
Selected volumetric data: |
||||||||
Natural gas pipeline transportation volumes (BBtus/d) |
13,421 |
14,198 |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Segment gross operating margin: |
||||||||
Propylene production and related activities |
$ |
471.0 |
$ |
445.1 |
||||
Butane isomerization and related operations |
67.6 |
79.9 |
||||||
Octane enhancement and related plant operations |
161.7 |
166.0 |
||||||
Refined products pipelines and related activities |
318.6 |
330.8 |
||||||
Ethylene exports and other services |
62.9 |
47.8 |
||||||
Total |
$ |
1,081.8 |
$ |
1,069.6 |
||||
Selected volumetric data: |
||||||||
Propylene production volumes (MBPD) |
89 |
97 |
||||||
Butane isomerization volumes (MBPD) |
96 |
109 |
||||||
Standalone DIB processing volumes (MBPD) |
127 |
99 |
||||||
Octane enhancement and related plant sales volumes (MBPD) (1) |
35 |
32 |
||||||
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) |
802 |
739 |
||||||
Marine terminal volumes, primarily refined products and petrochemicals (MBPD) |
262 |
325 |
(1) |
Reflects aggregate sales volumes for our octane additive and iBDH facilities located at our Mont Belvieu complex and our HPIB facility located adjacent to the Houston Ship Channel. |
Total |
2021 |
2022 |
2023 |
2024 |
2025 |
Thereafter |
||||||||||||||||||||||
Principal amount of senior and junior debt obligations |
$ |
30,146.4 |
$ |
1,325.0 |
$ |
1,400.0 |
$ |
1,250.0 |
$ |
850.0 |
$ |
1,150.0 |
$ |
24,171.4 |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Net cash flows provided by operating activities |
$ |
5,891.5 |
$ |
6,520.5 |
||||
Cash used in investing activities |
3,120.7 |
4,575.5 |
||||||
Cash used in financing activities |
2,022.7 |
1,945.1 |
• | a $310.1 million year-to-year decrease primarily due to higher levels of working capital employed in our marketing activities, which accounted for a $1.4 billion decrease, partially offset by the timing of cash receipts and payments related to operations; |
• | a $177.5 million year-to-year decrease resulting from lower partnership earnings in 2020 when compared to 2019 (determined by adjusting our $801.4 million year-to-year decrease in net income for changes in the non-cash items identified on our Statements of Consolidated Cash Flows); and |
• | a $141.4 million year-to-year decrease in cash distributions attributable to earnings from unconsolidated affiliates, with those unconsolidated affiliates owning crude oil pipelines and terminals accounting for substantially all of the decrease. |
• | a $1.24 billion year-to-year decrease in investments for property, plant and equipment (see “Capital Investments” within this Part II, Item 7 for additional information); |
• | a $124.2 million year-to-year increase in cash distributions attributable to the return of capital from unconsolidated affiliates, with those unconsolidated affiliates owning crude oil pipelines and terminals accounting for a majority of the increase; and |
• | a $96.0 million year-to-year decrease in investments in unconsolidated affiliates primarily due to lower cash outlays for NGL and crude oil pipeline projects. |
• | a $601.9 million year-to-year decrease in cash contributions from noncontrolling interests. In July 2019, an affiliate of Apache Corporation acquired a noncontrolling 33% equity interest in our consolidated subsidiary that owns the Shin Oak NGL Pipeline for $440.7 million. In addition, cash contributions from noncontrolling interests in connection with our Pascagoula natural gas processing plant and ethylene export facility decreased a combined $105.5 million year-to-year; |
• | a $105.2 million year-to-year increase in cash used to acquire common units under our 2019 Buyback Program; |
• | an $82.2 million year-to-year decrease in net cash proceeds from the issuance of common units under our distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, the Partnership announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP; and |
• | a $51.2 million year-to-year increase in cash distributions paid to common unitholders attributable to increases in the quarterly cash distribution rate per unit; partially offset by |
• | a net $757.4 million year-to-year increase in net cash inflows from debt. In 2020, we issued $4.25 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.5 billion principal amount of senior notes. In 2019, we issued $2.5 billion aggregate principal amount of senior notes, partially offset by the repayment or repurchase of $1.52 billion principal amount of senior and junior subordinated notes. In addition, net repayments of short term notes under EPO’s commercial paper program were $481.8 million in 2020 compared to net issuances of $481.8 million in 2019; and |
• | a $31.5 million increase in net cash proceeds from the issuance of preferred units in September 2020. |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Net income attributable to common unitholders (GAAP) (1) |
$ |
3,774.7 |
$ |
4,591.3 |
||||
Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): |
||||||||
Depreciation, amortization and accretion expenses |
2,071.9 |
1,949.3 |
||||||
Cash distributions received from unconsolidated affiliates (2) |
614.1 |
631.3 |
||||||
Equity in income of unconsolidated affiliates |
(426.1 |
) |
(563.0 |
) |
||||
Asset impairment and related charges |
890.6 |
132.8 |
||||||
Change in fair market value of derivative instruments |
(79.3 |
) |
27.2 |
|||||
Change in fair value of Liquidity Option |
2.3 |
119.6 |
||||||
Deferred income tax expense (benefit) |
(147.6 |
) |
20.0 |
|||||
Sustaining capital expenditures (3) |
(293.6 |
) |
(325.2 |
) |
||||
Other, net |
20.2 |
20.0 |
||||||
Operational DCF (4) |
$ |
6,427.2 |
$ |
6,603.3 |
||||
Proceeds from asset sales |
12.8 |
20.6 |
||||||
Monetization of interest rate derivative instruments accounted for as cash flow hedges |
(33.3 |
) |
– |
|||||
DCF (non-GAAP) |
$ |
6,406.7 |
$ |
6,623.9 |
||||
Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards |
$ |
3,926.9 |
$ |
3,887.0 |
||||
Cash distribution per common unit declared by Enterprise GP with respect to period (5) |
$ |
1.7850 |
$ |
1.7650 |
||||
Total DCF retained by the Partnership with respect to period (6) |
$ |
2,479.8 |
$ |
2,736.9 |
||||
Distribution coverage ratio (7) |
1.63 |
x |
1.70 |
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 distributions received from unconsolidated affiliates attributable to earnings and the return of capital. |
(3) |
Sustaining capital expenditures include cash payments and accruals applicable to the period. |
(4) |
Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges. |
(5) |
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. |
(6) |
At the sole discretion of Enterprise GP, cash retained by the partnership with respect to each of these periods was primarily reinvested in growth capital projects. This retainage of cash substantially reduced our reliance on the equity capital markets to fund such expenditures. |
(7) |
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, |
||||||||
2020 |
2019 |
|||||||
Net cash flows provided by operating activities (GAAP) |
$ |
5,891.5 |
$ |
6,520.5 |
||||
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 |
767.5 |
457.4 |
||||||
Sustaining capital expenditures |
(293.6 |
) |
(325.2 |
) |
||||
Distributions received from unconsolidated affiliates attributable to the return of capital |
187.5 |
63.3 |
||||||
Proceeds from asset sales |
12.8 |
20.6 |
||||||
Net income attributable to noncontrolling interest |
(110.1 |
) |
(95.8 |
) |
||||
Monetization of interest rate derivative instruments accounted for as cash flow hedges |
(33.3 |
) |
– |
|||||
Other, net |
(15.6 |
) |
(16.9 |
) |
||||
DCF (non-GAAP) |
$ |
6,406.7 |
$ |
6,623.9 |
For the Year Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Net cash flows provided by operating activities (GAAP) |
$ |
5,891.5 |
$ |
6,520.5 |
||||
Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign): |
||||||||
Cash used in investing activities |
(3,120.7 |
) |
(4,575.5 |
) |
||||
Cash contributions from noncontrolling interests |
30.9 |
632.8 |
||||||
Cash distributions paid to noncontrolling interests |
(131.3 |
) |
(106.2 |
) |
||||
FCF (non-GAAP) |
$ |
2,670.4 |
$ |
2,471.6 |
For the Years Ended December 31, |
||||||||
2020 |
2019 |
|||||||
Capital investments for property, plant and equipment: (1) |
||||||||
Growth capital projects (2) |
$ |
2,985.8 |
$ |
4,208.1 |
||||
Sustaining capital projects (3) |
302.1 |
323.6 |
||||||
Total |
$ |
3,287.9 |
$ |
4,531.7 |
||||
Investments in unconsolidated affiliates |
$ |
15.6 |
$ |
111.6 |
(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 expenditures are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. |
• | Frac X and Frac XI in March 2020 and September 2020, respectively; |
• | expansion projects on the Texas Express Pipeline and Front Range Pipeline in April 2020; |
• | the Midland-to-ECHO segment of the Midland-to-Webster pipeline in October 2020; and |
• | refrigerated storage at our ethylene export terminal in December 2020. |
• | completion of projects at our Mont Belvieu complex, which accounted for a $759.7 million decrease and included placing into service our iBDH facility (December 2019), Frac X (March 2020) and Frac XI (September 2020); |
• | lower investments in natural gas processing facilities and related infrastructure that support Permian Basin production, which accounted for a $372.4 million decrease. We completed the final phase of our Orla plant in July 2019 and placed our Mentone plant into service in December 2019; |
• | completion of the Shin Oak NGL Pipeline (in stages through the fourth quarter of 2019), which accounted for a $353.2 million decrease; and |
• | lower investments in projects attributable to our ethylene business, which accounted for a $175.3 million decrease; partially offset by, |
• | higher investments in our PDH 2 facility, which accounted for a $335.7 million increase; |
• | higher investments in crude oil pipelines, including those expanding our Midland-to-ECHO System, and related infrastructure that support Permian Basin production, which accounted for a combined $82.2 million increase; and |
• | higher investments in natural gas pipelines and related infrastructure in support of East Texas and Louisiana production, which accounted for a $47.9 million increase. |
Selected asset information: |
||||
Current receivables from Non-Obligor Subsidiaries |
$ |
775.4 |
||
Other current assets |
5,805.7 |
|||
Long-term receivables from Non-Obligor Subsidiaries |
187.3 |
|||
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $45.98 billion |
8,198.5 |
|||
Selected liability information: |
||||
Current portion of Guaranteed Debt, including interest of $455.6 million |
$ |
1,780.6 |
||
Current payables to Non-Obligor Subsidiaries |
1,129.0 |
|||
Other current liabilities |
3,858.6 |
|||
Noncurrent portion of Guaranteed Debt, principal only |
28,806.8 |
|||
Noncurrent payables to Non-Obligor Subsidiaries |
27.0 |
|||
Other noncurrent liabilities |
42.9 |
|||
Mezzanine equity of Obligor Group: |
||||
Preferred units |
$ |
49.3 |
Revenues from Non-Obligor Subsidiaries |
$ |
2,602.4 |
||
Revenues from other sources |
15,361.4 |
|||
Operating income of Obligor Group |
1,069.7 |
|||
Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $3.54 billion |
(157.0 |
) |
Payment or Settlement due by Period |
||||||||||||||||||||
In less than |
In 1-3 |
In 4-5 |
More than |
|||||||||||||||||
Contractual Obligations |
Total |
1 year |
years |
years |
5 years |
|||||||||||||||
Scheduled maturities of debt obligations (1) |
$ |
30,146.4 |
$ |
1,325.0 |
$ |
2,650.0 |
$ |
2,000.0 |
$ |
24,171.4 |
||||||||||
Estimated cash payments for interest (2) |
28,834.6 |
1,294.0 |
2,442.2 |
2,284.2 |
22,814.2 |
|||||||||||||||
Operating lease obligations (3) |
460.5 |
33.7 |
69.3 |
58.7 |
298.8 |
|||||||||||||||
Purchase obligations: |
||||||||||||||||||||
Product purchase commitments (4) |
14,800.7 |
2,266.6 |
4,230.6 |
3,501.4 |
4,802.1 |
|||||||||||||||
Service payment commitments (4,5) |
278.8 |
62.0 |
102.0 |
29.0 |
85.8 |
|||||||||||||||
Other long-term liabilities (6) |
365.8 |
– |
85.8 |
50.8 |
229.2 |
|||||||||||||||
Total contractual payment obligations |
$ |
74,886.8 |
$ |
4,981.3 |
$ |
9,579.9 |
$ |
7,924.1 |
$ |
52,401.5 |
(1) |
Represents scheduled future maturities of our current and long-term debt principal obligations. For information regarding our consolidated debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. |
(2) |
Estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2020, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are influenced by the long-term maturities of our $2.65 billion in junior subordinated notes (due June 2067 through February 2078). The estimated cash payments assume that (i) the junior subordinated notes are not repaid prior to their respective maturity dates and (ii) the amount of interest paid on the junior subordinated notes is based on either (a) the current fixed interest rate charged or (b) the weighted-average variable rate paid in 2020, as applicable, for each note through the respective maturity date. |
(3) |
Primarily represents (i) land held pursuant to property leases, (ii) the lease of underground storage caverns for natural gas and NGLs, (iii) the lease of transportation equipment used in our operations and (iv) office space leased from affiliates of EPCO. |
(4) |
Represents enforceable and legally binding agreements to purchase goods or services as of December 31, 2020. The estimated payment obligations are based on contractual prices in effect at December 31, 2020 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. |
(5) |
Primarily represents our unconditional payment obligations under firm pipeline transportation contracts. |
(6) |
Primarily represents the noncurrent portion of asset retirement obligations and deferred revenues. |
• | 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. |
Volume (1) |
Accounting |
||
Derivative Purpose |
Current (2) |
Long-Term (2) |
Treatment |
Derivatives designated as hedging instruments: |
|||
Natural gas processing: |
|||
Forecasted natural gas purchases for plant thermal reduction (billion cubic feet (“Bcf”)) |
6.0 |
n/a |
Cash flow hedge |
Forecasted sales of NGLs (million barrels (“MMBbls”)) (3) |
0.6 |
n/a |
Cash flow hedge |
Natural gas marketing: |
|||
Natural gas storage inventory management activities (Bcf) |
4.0 |
n/a |
Fair value hedge |
NGL marketing: |
|||
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) |
142.8 |
1.6 |
Cash flow hedge |
Forecasted sales of NGLs and related hydrocarbon products (MMBbls) |
172.1 |
4.5 |
Cash flow hedge |
NGLs inventory management activities (MMBbls) |
1.9 |
n/a |
Fair value hedge |
Refined products marketing: |
|||
Forecasted purchases of refined products (MMBbls) |
41.2 |
n/a |
Cash flow hedge |
Forecasted sales of refined products (MMBbls) |
51.1 |
3.3 |
Cash flow hedge |
Refined products inventory management activities (MMBbls) |
0.8 |
n/a |
Fair value hedge |
Crude oil marketing: |
|||
Forecasted purchases of crude oil (MMBbls) |
32.9 |
n/a |
Cash flow hedge |
Forecasted sales of crude oil (MMBbls) |
44.5 |
n/a |
Cash flow hedge |
Petrochemical marketing: |
|||
Forecasted purchases of petrochemical products (MMBbls) |
0.4 |
n/a |
Cash flow hedge |
Forecasted sales of petrochemical products (MMBbls) |
0.5 |
n/a |
Cash flow hedge |
Derivatives not designated as hedging instruments: |
|||
Natural gas risk management activities (Bcf) (3) |
10.3 |
0.4 |
Mark-to-market |
NGL risk management activities (MMBbls) (3) |
26.5 |
7.9 |
Mark-to-market |
Refined products risk management activities (MMBbls) (3) |
6.9 |
n/a |
Mark-to-market |
Crude oil risk management activities (MMBbls) (3) |
32.5 |
2.6 |
Mark-to-market |
(1) |
Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. |
(2) |
The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2022, December 2021 and October 2023, respectively. |
(3) |
Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets. |
Portfolio Fair Value at |
|||||||||||||
Scenario |
Resulting Classification |
December 31, 2019 |
December 31, 2020 |
January 29, 2021 |
|||||||||
Fair value assuming no change in underlying commodity prices |
Asset (Liability) |
$ |
1.1 |
$ |
3.7 |
$ |
3.3 |
||||||
Fair value assuming 10% increase in underlying commodity prices |
Asset (Liability) |
(4.3 |
) |
2.6 |
2.6 |
||||||||
Fair value assuming 10% decrease in underlying commodity prices |
Asset (Liability) |
6.6 |
4.9 |
4.1 |
Portfolio Fair Value at |
|||||||||||||
Scenario |
Resulting Classification |
December 31, 2019 |
December 31, 2020 |
January 29, 2021 |
|||||||||
Fair value assuming no change in underlying commodity prices |
Asset (Liability) |
$ |
43.7 |
$ |
(388.2 |
) |
$ |
(286.9 |
) |
||||
Fair value assuming 10% increase in underlying commodity prices |
Asset (Liability) |
(19.0 |
) |
(521.0 |
) |
(359.6 |
) |
||||||
Fair value assuming 10% decrease in underlying commodity prices |
Asset (Liability) |
106.4 |
(255.4 |
) |
(214.1 |
) |
Portfolio Fair Value at |
|||||||||||||
Scenario |
Resulting Classification |
December 31, 2019 |
December 31, 2020 |
January 29, 2021 |
|||||||||
Fair value assuming no change in underlying commodity prices |
Asset (Liability) |
$ |
(9.6 |
) |
$ |
(184.3 |
) |
$ |
(225.3 |
) |
|||
Fair value assuming 10% increase in underlying commodity prices |
Asset (Liability) |
(50.6 |
) |
(266.5 |
) |
(315.0 |
) |
||||||
Fair value assuming 10% decrease in underlying commodity prices |
Asset (Liability) |
31.5 |
(102.1 |
) |
(135.7 |
) |
Hedged Transaction |
Number and Type of Derivatives Outstanding |
Notional Amount |
Expected Settlement Date |
Weighted-Average Fixed Rate Locked |
Accounting Treatment |
Future long-term debt offering |
1 forward-starting swap |
$75.0 |
4/2021 |
2.41% |
Cash flow hedge |
Future long-term debt offering |
5 forward-starting swaps |
$500.0 |
4/2021 |
2.13% |
Cash flow hedge |
Future long-term debt offering |
2 forward-starting swaps (1) |
$150.0 |
2/2022 |
1.72% |
Cash flow hedge |
Future long-term debt offering |
1 forward starting swap (1) |
$100.0 |
4/2021 |
1.46% |
Cash flow hedge |
Future long-term debt offering |
2 forward starting swaps (1) |
$150.0 |
2/2022 |
1.48% |
Cash flow hedge |
Future long-term debt offering |
2 forward starting swaps (1) |
$100.0 |
2/2022 |
0.95% |
Cash flow hedge |
(1) |
These swaps were entered into during the first quarter of 2020. |
Portfolio Fair Value at |
|||||||||||||
Scenario |
Resulting Classification |
December 31, 2019 |
December 31, 2020 |
January 29, 2021 |
|||||||||
Fair value assuming no change in underlying interest rates |
Asset (Liability) |
$ |
(13.5 |
) |
$ |
(107.7 |
) |
$ |
(48.3 |
) |
|||
Fair value assuming 10% increase in underlying interest rates |
Asset (Liability) |
38.2 |
(69.4 |
) |
(6.8 |
) |
|||||||
Fair value assuming 10% decrease in underlying interest rates |
Asset (Liability) |
(68.3 |
) |
(147.6 |
) |
(91.8 |
) |
(i) | that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive and financial officers, as appropriate to allow for timely decisions regarding required disclosures; and |
(ii) | that our disclosure controls and procedures are effective. |
/s/ A. James Teague |
/s/ W. Randall Fowler |
|||
Name: |
A. James Teague |
Name: |
W. Randall Fowler |
|
Title: |
Co-Chief Executive Officer |
Title: |
Co-Chief Executive Officer |
|
of Enterprise Products Holdings LLC |
and Chief Financial Officer |
|||
of Enterprise Products Holdings LLC |
• | our strategic direction (including business opportunities through organic growth and acquisitions); |
• | the vision, leadership and development of our management team; |
• | our business goals and operational performance; and |
• | strategies to preserve our financial strength. |
Name |
Age |
Position with Enterprise GP |
Randa Duncan Williams (1,2,6) |
59 |
Director and Chairman of the Board |
Richard H. Bachmann (1,6) |
68 |
Director and Vice Chairman of the Board |
A. James Teague (1,6,7,8) |
75 |
Director and Co-CEO |
W. Randall Fowler (1,6,7,8) |
64 |
Director, Co-CEO and CFO |
Carin M. Barth (2,6) |
58 |
Director |
Murray E. Brasseux (4) |
72 |
Director |
James T. Hackett (2,3,6) |
67 |
Director |
William C. Montgomery (4,5) |
59 |
Director |
John R. Rutherford (4) |
60 |
Director |
Richard S. Snell (4,6) |
78 |
Director |
Harry P. Weitzel (6,8) |
56 |
Director and Executive Vice President, General Counsel and Secretary |
Graham W. Bacon (8) |
57 |
Executive Vice President and Chief Operating Officer |
R. Daniel Boss (8) |
45 |
Executive Vice President – Accounting, Risk Control and Information Technology |
Christian M. Nelly (8) |
45 |
Executive Vice President – Finance and Sustainability and Treasurer |
Brent B. Secrest (8) |
48 |
Executive Vice President and Chief Commercial Officer |
Michael W. Hanson (8) |
53 |
Vice President and Principal Accounting 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 40 years of commercial management of midstream assets and marketing and trading activities, both for third parties and for us; |
• | for Mr. Fowler, over 20 years of experience with our midstream assets, including finance, accounting and investor relations and, for over 15 years, as a member of our executive management team; |
• | for Mr. Bachmann, over 30 years of experience with our midstream assets, including legal, regulatory, contracts and mergers and acquisitions and, for over 20 years, as a member of either EPCO’s or our executive management teams; and |
• | for Mr. Weitzel, over 25 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 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; |
• | 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); and |
• | for Mr. Snell, professional experience involving complex legal and accounting matters. |
Equity- |
||||||
Cash |
Based |
All Other |
||||
Name and |
Salary |
Bonus |
Awards |
Compensation |
Total |
|
Principal Position |
Year |
($) |
($) |
($) (1) |
($) (2) |
($) |
A. James Teague, |
2020 |
$ 937,572 |
$ 3,000,000 |
$ 5,796,000 |
$ 915,797 |
$ 10,649,369 |
Co-CEO |
2019 |
887,500 |
3,000,000 |
5,827,500 |
822,661 |
10,537,661 |
2018 |
837,500 |
2,716,250 |
4,359,306 |
706,531 |
8,619,587 |
|
W. Randall Fowler, |
2020 |
660,938 |
2,250,000 |
4,399,950 |
637,630 |
7,948,518 |
Co-CEO and CFO |
2019 |
609,375 |
2,250,000 |
3,663,000 |
519,072 |
7,041,447 |
2018 |
567,188 |
1,845,000 |
2,736,631 |
430,337 |
5,579,156 |
|
Graham W. Bacon, |
2020 |
511,250 |
700,000 |
2,318,400 |
418,486 |
3,948,136 |
Executive Vice President and |
2019 |
481,250 |
500,000 |
2,358,750 |
386,692 |
3,726,692 |
Chief Operating Officer |
2018 |
418,750 |
411,000 |
3,159,310 |
315,136 |
4,304,196 |
Brent B. Secrest, |
2020 |
468,750 |
700,000 |
2,356,199 |
315,031 |
3,839,980 |
Executive Vice President and |
2019 |
390,000 |
500,000 |
1,248,750 |
219,012 |
2,357,762 |
Chief Commercial Officer |
2018 |
332,500 |
359,750 |
2,007,334 |
168,921 |
2,868,505 |
Christian M. Nelly, |
2020 |
336,375 |
390,000 |
1,109,471 |
659,699 |
2,495,545 |
Executive Vice President – Finance and Sustainability and Treasurer |
(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 2020” within this Item 11 for information regarding awards granted in the year ended December 31, 2020. |
(2) |
Amounts include (i) contributions in connection with funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid on equity-based awards, (iii) the imputed value of life insurance premiums paid on behalf of the officer, (iv) employee retention payments and (v) other amounts. |
Named Executive Officer |
Contributions Under Funded, Qualified, Defined Contribution Retirement Plans |
Distributions Paid On Equity-Based Awards (1) |
Life Insurance Premiums |
Employee Retention Payments (2) |
Other |
Total All Other Compensation |
||||||||||||||||||
A. James Teague |
$ |
34,200 |
$ |
870,867 |
$ |
5,438 |
$ |
– |
$ |
5,292 |
$ |
915,797 |
||||||||||||
W. Randall Fowler |
25,650 |
603,898 |
3,267 |
– |
4,815 |
637,630 |
||||||||||||||||||
Graham W. Bacon |
34,200 |
376,020 |
2,838 |
– |
5,428 |
418,486 |
||||||||||||||||||
Brent B. Secrest |
31,350 |
276,960 |
990 |
– |
5,731 |
315,031 |
||||||||||||||||||
Christian M. Nelly |
30,566 |
135,416 |
965 |
487,500 |
5,252 |
659,699 |
(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, 2020: Mr. Teague, $862,677; Mr. Fowler, $575,539; Mr. Bacon, $350,660; Mr. Secrest, $243,916; and Mr. Nelly, $111,826. |
(2) |
Amount presented for Mr. Nelly relates to a two-year employee retention agreement that settled in August 2020 and reflects the amount charged to us based on the percentage of time that Mr. Nelly spent on our business and affairs since the retention agreement was originally executed. For information regarding active employee retention agreements involving our named executive officers see “Compensation Discussion and Analysis” below. |
Grant |
|||||
Date Fair |
|||||
Value of |
|||||
Estimated Future Payouts Under |
Equity- |
||||
Equity Incentive Plan Awards |
Based |
||||
Grant |
Threshold |
Target |
Maximum |
Awards |
|
Award Type/Named Executive Officer |
Date |
(#) |
(#) |
(#) |
($) (1) |
Phantom unit awards: (2) |
|||||
A. James Teague |
2/06/20 |
– |
225,000 |
– |
$ 5,796,000 |
W. Randall Fowler |
2/06/20 |
– |
225,000 |
– |
4,347,000 |
Graham W. Bacon |
2/06/20 |
– |
90,000 |
– |
2,318,400 |
Brent B. Secrest |
2/06/20 |
– |
90,000 |
– |
2,318,400 |
Christian M. Nelly |
2/06/20 |
– |
43,000 |
– |
1,079,988 |
Profits interest awards: |
|||||
W. Randall Fowler (3) |
9/30/20 |
– |
– |
– |
52,950 |
Brent B. Secrest (4) |
9/30/20 |
– |
– |
– |
37,799 |
Christian M. Nelly (4) |
9/30/20 |
– |
– |
– |
29,483 |
(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 2020. Based on current allocations, we estimate that the compensation expense we record for each named executive officer with respect to these awards will equal these amounts over time. |
(2) |
The grant date fair value presented for the phantom unit awards is based, in part, on the closing price of our common units on February 6, 2020 of $25.76 per unit. |
(3) |
Represents the incremental fair value of the modification of Mr. Fowler’s profits interest award in PrivCo I, computed as of the amendment date of September 30, 2020. |
(4) |
Represents the incremental fair value of the modification of Mr. Secrest’s and Mr. Nelly’s respective profits interest awards in PubCo II, computed as of the amendment date of September 30, 2020. |
Unit Awards |
||
Number of |
||
Units |
Value |
|
Acquired on |
Realized on |
|
Vesting |
Vesting |
|
Named Executive Officer |
(#) (1) |
($) |
A. James Teague: |
||
Vesting of phantom unit awards (2) |
168,400 |
$ 4,373,348 |
Vesting of profits interest award – PubCo I (3) |
16,009 |
419,916 |
W. Randall Fowler: |
||
Vesting of phantom unit awards (2) |
137,262 |
3,564,694 |
Graham W. Bacon: |
||
Vesting of phantom unit awards (2) |
69,000 |
1,791,930 |
Vesting of profits interest award – PubCo I (3) |
18,296 |
479,904 |
Brent B. Secrest: |
||
Vesting of phantom unit awards (2) |
33,125 |
860,256 |
Christian M. Nelly: |
||
Vesting of phantom unit awards (2) |
14,717 |
382,200 |
(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. |
(3) |
PubCo I vested in February 2020 and its assets (consisting of Partnership common units) were distributed to its partners, which included Mr. Teague and Mr. Bacon. The value realized on vesting was determined by multiplying the gross number of our common units received by the named executive officer by the closing price of our common units on the date of vesting. |
Unit Awards |
|||
Market |
|||
Number |
Value |
||
of Units |
of Units |
||
That Have |
That Have |
||
Not Vested |
Not Vested |
||
Award Type/Named Executive Officer |
(#) (1) |
($) (2,3) |
|
Phantom unit awards: (4) |
|||
A. James Teague |
498,800 |
$ 9,771,492 |
|
W. Randall Fowler |
453,050 |
8,875,250 |
|
Graham W. Bacon |
202,250 |
3,962,078 |
|
Brent B. Secrest |
151,250 |
2,962,988 |
|
Christian M. Nelly |
71,505 |
1,400,783 |
|
Profits interest awards: |
|||
W. Randall Fowler: |
|||
PrivCo I (5,6) |
– |
$ 0 |
|
Graham W. Bacon: |
|||
EPD IV (7) |
– |
0 |
|
Brent B. Secrest: |
|||
PubCo II (5,8) |
– |
0 |
|
EPD IV (7) |
– |
0 |
|
Christian M. Nelly: |
|||
PubCo II (5,8) |
– |
0 |
|
EPD IV (7) |
– |
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 31, 2020 (the last trading day of 2020) of $19.59 per unit. |
(3) |
With respect to amounts presented for the profits interest awards, amount represents the estimated liquidation value to be received by the named executive officer based on the closing price of Partnership common units on December 31, 2020 and the terms of liquidation outlined in the applicable Employee Partnership agreement. There was no residual profits interest in any of the Employee Partnerships due to a decrease in the market value of the Partnership common units they own since the formation date of each respective Employee Partnership. |
(4) |
Of the 1,376,855 phantom unit awards presented in the table, the vesting schedule is as follows: 497,430 in 2021; 407,675 in 2022; 303,500 in 2023 and 168,250 in 2024. |
(5) |
The vesting date of the profits interests awards for PrivCo I and PubCo II is the earlier of (i) February 22, 2023, (ii) the first date on or after September 30, 2020 on which the closing market price of our common units is equal to or greater than $25.41 per unit, (iii) a change of control event, or (iv) dissolution of the applicable Employee Partnership |
(6) |
Mr. Fowler’s share of the profits interest in PrivCo I was approximately 15.46% at December 31, 2020. |
(7) |
With respect to EPD IV, the profits interest share held by Messrs. Bacon, Secrest and Nelly at December 31, 2020 was approximately 5.00%, 4.00% and 2.50%, respectively. |
(8) |
With respect to PubCo II, the profits interest share held by Messrs. Secrest and Nelly at December 31, 2020 was approximately 3.25% and 2.60%, respectively. |
• | 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, 2020. There are approximately 7,130 EPCO personnel who spend all or a substantial portion of their time engaged in our business. |
• | Second, basic wage data for each active EPCO employee, excluding Mr. Teague, Mr. Fowler and those on long-term disability, was extracted from Form W-2 information provided to the Internal Revenue Service for fiscal 2020. 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 2020 was determined using the same method used to determine Mr. Teague’s and Mr. Fowler’s total annual compensation for 2020 as presented in the Summary Compensation Table within this Part III, Item 11. |
• | each received an $87,049 annual cash retainer and an annual grant of our common units having a fair market value, based on the closing price of our common units on the trading day immediately preceding the date of grant, of $85,000; |
• | if the individual served as a chairman of the Audit and Conflicts Committee, then such individual received an additional $20,000 annual cash retainer; |
• | if the individual served as a chairman of the Governance Committee, then such individual received an additional $15,000 annual cash retainer; and, |
• | for those independent voting directors that served on the Capital Projects Committee, a $2,500 per meeting cash fee for attendance at meetings of this committee. |
Fees Earned |
Value of |
|||||||||||
or Paid |
Equity-Based |
|||||||||||
in Cash |
Awards |
Total |
||||||||||
Independent Voting Director |
($) |
($) |
($) |
|||||||||
Carin M. Barth |
$ |
87,049 |
$ |
85,000 |
$ |
172,049 |
||||||
Murray E. Brasseux |
87,049 |
85,000 |
172,049 |
|||||||||
James T. Hackett (1) |
102,049 |
85,000 |
187,049 |
|||||||||
William C. Montgomery (2) |
107,049 |
85,000 |
192,049 |
|||||||||
John R. Rutherford |
87,049 |
85,000 |
172,049 |
|||||||||
Richard S. Snell |
87,049 |
85,000 |
172,049 |
(1) |
Mr. Hackett serves as chairman of the Governance Committee. |
(2) |
Mr. Montgomery serves as chairman of the Audit and Conflicts Committee. |
Amount and |
|||
Nature of |
|||
Name and Address |
Beneficial |
Percent |
|
of Beneficial Owner |
Title of Class |
Ownership |
of Class |
Randa Duncan Williams (1) |
Common Units |
702,186,015 |
32.2% |
1100 Louisiana Street, 10th Floor |
Series A Cumulative Convertible Preferred Units |
15,412 |
30.6% |
Houston, Texas 77002 |
(1) |
For a detailed listing of the ownership amounts that comprise Ms. Duncan Williams’ total beneficial ownership of our limited partner units, see the table presented in the following section, “Security Ownership of Management,” within this Part III, Item 12. |
Amount and Nature Of |
||||||||||
Positions with |
Beneficial Ownership |
Percent of Class |
||||||||
Enterprise GP |
Common |
Preferred |
Common |
Preferred |
||||||
at February 19, 2021 |
Units |
Units |
Units |
Units |
||||||
Randa Duncan Williams: |
Director and Chairman of the Board |
|||||||||
Common units: |
||||||||||
Units controlled by EPCO Voting Trust: |
||||||||||
Through EPCO |
74,754,703 |
3.4% |
||||||||
Through EPCO Holdings, Inc. |
593,479,815 |
27.2% |
||||||||
Through Employee Partnerships |
11,945,636 |
* |
||||||||
Units controlled by Alkek and Williams, Ltd. |
455,097 |
* |
||||||||
Units controlled by Chaswil, Ltd. |
75,736 |
* |
||||||||
Units controlled by family trusts (1) |
21,279,948 |
* |
||||||||
Units owned personally (2) |
195,080 |
* |
||||||||
Preferred units: |
||||||||||
Units controlled by Manxome Investors L.P. |
15,412 |
30.6% |
||||||||
Total for Randa Duncan Williams |
702,186,015 |
15,412 |
32.2% |
30.6% |
* Represents a beneficial ownership of less than 1% of class |
|||||
(1) |
The number of common units presented for Ms. Duncan Williams includes common units held by family trusts for which she serves as a director of an entity trustee but has disclaimed beneficial ownership (except to the extent of her pecuniary interest therein). |
||||
(2) |
The number of common units presented for Ms. Duncan Williams includes 9,090 common units held by her spouse and 4,040 common units held jointly with her spouse. |
Common Units |
||||||
Amount and |
||||||
Positions with |
Nature Of |
|||||
Enterprise GP |
Beneficial |
Percent of |
||||
at February 19, 2021 |
Ownership |
Class |
||||
Richard H. Bachmann (1) |
Director and Vice Chairman of the Board |
1,731,611 |
* |
|||
A. James Teague (2,3) |
Director and Co-CEO |
2,208,826 |
* |
|||
W. Randall Fowler (2,4) |
Director, Co-CEO and CFO |
1,691,932 |
* |
|||
Carin M. Barth |
Director |
62,051 |
* |
|||
Murray E. Brasseux (5) |
Director |
28,398 |
* |
|||
James T. Hackett (6) |
Director |
280,209 |
* |
|||
William C. Montgomery |
Director |
57,551 |
* |
|||
John R. Rutherford |
Director |
32,716 |
* |
|||
Richard S. Snell (7) |
Director |
84,966 |
* |
|||
Harry P. Weitzel |
Director and Executive Vice President, General Counsel and Secretary |
106,508 |
* |
|||
Graham W. Bacon (2) |
Executive Vice President and Chief Operating Officer |
372,901 |
* |
|||
Brent B. Secrest (2) |
Executive Vice President and Chief Commercial Officer |
128,254 |
* |
|||
Christian M. Nelly (2) |
Executive Vice President – Finance and Sustainability and Treasurer |
89,212 |
* |
|||
All directors and executive officers (including all named executive officers) of Enterprise GP, as a group (16 individuals in total) |
709,302,393 |
32.5% |
* Represents a beneficial ownership of less than 1% of class |
|||||
(1) |
The number of common units presented for Mr. Bachmann includes 9,588 common units held by his spouse. |
||||
(2) |
These individuals are named executive officers for the year ended December 31, 2020. |
||||
(3) |
The number of common units presented for Mr. Teague includes (i) 61,746 common units held by a trust and (ii) 39,055 common units held by his spouse. |
||||
(4) |
The number of common units presented for Mr. Fowler includes 610,000 common units held by a family limited partnership (for which he has disclaimed beneficial ownership except to the extent of his 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 Mr. Hackett includes (i) 9,661 common units held by family trusts and (ii) 33,000 common units held by a family limited partnership. |
||||
(7) |
The number of common units presented for Mr. Snell includes 2,956 common units held by his spouse. |
• | each non-management director of Enterprise GP is required to own our common units having an aggregate value (as defined in the guidelines) of three times the dollar amount of such non-management director’s aggregate annual cash retainer for service on the Board for the most recently completed calendar year; and |
• | each executive officer of Enterprise GP is required to own our common units having an aggregate value (as defined in the guidelines) of three times the dollar amount of such executive officer’s aggregate annual base salary for the most recently completed calendar year. |
Number of |
||||
Units |
||||
Remaining |
||||
Available For |
||||
Number of |
Future Issuance |
|||
Units to |
Weighted- |
Under Equity |
||
Be Issued |
Average |
Compensation |
||
Upon Exercise |
Exercise Price |
Plans (excluding |
||
of Outstanding |
of Outstanding |
securities |
||
Common Unit |
Common Unit |
reflected in |
||
Plan Category |
Options |
Options |
column (a)) |
|
(a) |
(b) |
(c) |
||
Equity compensation plans approved by unitholders: |
||||
2008 Plan (1) |
– |
– |
21,229,995 |
|
Equity compensation plans not approved by unitholders: |
||||
None |
– |
– |
– |
|
Total for equity compensation plans |
– |
– |
21,229,995 |
(1) |
At December 31, 2020, the total number of common units authorized for issuance under the 2008 Plan was 55,000,000 common units. This amount increased by 5,000,000 common units on January 1, 2021 and will increase by an additional 5,000,000 common units subsequently on each January 1 thereafter during the term of the 2008 Plan; provided, however, that in no event shall the maximum aggregate amount available for issuance under the 2008 Plan exceed 70,000,000 common units. |
• | pursuant to our partnership agreement or the limited liability company agreement of Enterprise GP, as such agreements may be amended from time to time; |
• | in which an officer or director of Enterprise GP or any of our subsidiaries, or an immediate family member of such an officer or director, has a material financial interest or is otherwise a party; |
• | when requested to do so by management or the Board; |
• | with a value of $5 million or more (unless such transaction is equivalent to an arm’s length 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, |
||||||||
2020 |
2019 |
|||||||
Audit fees (1) |
$ |
5,155,475 |
$ |
5,091,440 |
(1) |
Audit fees for 2020 and 2019 include $50,000 and $40,000, respectively, of charges for audit-related projects that were reimbursed by business partners. |
(1) | Financial Statements: See “Index to Consolidated Financial Statements” beginning on page F-1 of this annual report for the financial statements included herein. |
(2) | Financial Statement Schedules: The separate filing of financial statement schedules has been omitted because such schedules are either not applicable or the information called for therein appears in the footnotes of our Consolidated Financial Statements. |
(3) | Exhibits: |
Exhibit Number |
Exhibit* |
2.1 |
|
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 |
|
3.8 |
|
3.9 |
|
3.10 |
|
3.11 |
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 |
|
4.34 |
|
4.35 |
|
4.36 |
|
4.37 |
|
4.38 |
|
4.39 |
|
4.40 |
|
4.41 |
|
4.42 |
|
4.43 |
4.44 |
|
4.45 |
|
4.46 |
|
4.47 |
|
4.48 |
|
4.49 |
|
4.50 |
|
4.51 |
|
4.52 |
|
4.53 |
|
4.54 |
|
4.55 |
|
4.56 |
|
4.57 |
|
4.58 |
|
4.59 |
|
4.60 |
4.61 |
|
4.62 |
|
4.63 |
|
4.64 |
|
4.65 |
|
4.66 |
|
4.67 |
|
4.68 |
|
4.69 |
|
4.70 |
|
4.71 |
|
4.72 |
|
4.73 |
|
4.74 |
|
4.75 |
4.76 |
|
4.77 |
|
4.78 |
|
4.79 |
|
4.80 |
|
4.81 |
|
4.82 |
|
4.83 |
|
4.84 |
|
4.85 |
|
4.86 |
|
4.87 |
10.1*** |
|
10.2*** |
|
10.3***# |
|
10.4 |
|
10.5 |
|
10.6 |
|
10.7 |
|
10.8 |
|
10.9 |
|
10.10 |
|
10.11 |
|
10.12*** |
|
10.13*** |
|
10.14*** |
|
10.15*** |
|
10.16*** |
* |
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 |
By: |
/s/ Michael W. Hanson |
Name: |
Michael W. Hanson |
Title: |
Vice President and Principal Accounting Officer 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/ James T. Hackett |
Director |
|
James T. Hackett |
||
/s/ William C. Montgomery |
Director |
|
William C. Montgomery |
||
/s/ John R. Rutherford |
Director |
|
John R. Rutherford |
||
/s/ Richard S. Snell |
Director |
|
Richard S. Snell |
||
/s/ R. Daniel Boss |
Executive Vice President – Accounting, Risk Control and Information Technology |
|
R. Daniel Boss |
||
/s/ Michael W. Hanson |
Vice President and Principal Accounting Officer |
|
Michael W. Hanson |
Page No. |
||
• |
We tested the effectiveness of controls over goodwill, including those over the assumptions related to planned capital projects and related contract fees underlying the forecasted operating margin, the long-term growth rate for cash flows beyond the discrete forecast period, and the discount rate. |
• |
We evaluated management’s ability to reasonably forecast operating margin by performing a look-back test comparing actual results to management’s historical forecasts. |
• |
We evaluated the reasonableness of management’s operating margin forecast for planned capital projects and related contract fees by comparing the forecast to: |
- |
Internal communications to management and the Board of Directors regarding the projects. |
- |
Forecasted information regarding the projects included in analyst and industry reports for the Company and certain of its peer companies. |
• |
With the assistance of our fair value specialists, we evaluated the reasonableness of the long-term growth rate for cash flows beyond the discrete forecast period and the discount rate by: |
- |
Testing the source information underlying the determination of the long-term growth rate and discount rate, and the mathematical accuracy of the calculations. |
- |
Developing a range of independent estimates and comparing those to the long-term growth rate and discount rate selected by management. |
• |
We tested the effectiveness of property, plant and equipment controls over the review of assumptions underlying the forecasted operating margin, the long-term growth rate for cash flows beyond the discrete forecast period, and the discount rate. |
• |
We evaluated management’s ability to reasonably forecast operating margin by: |
- |
Performing a look-back test comparing actual results to management’s historical forecasts. |
- |
Performing a sensitivity analysis to evaluate the change in the fair value estimate that would result from changes in certain underlying assumptions. |
• |
With the assistance of our fair value specialists, we evaluated the reasonableness of the long-term growth rate for cash flows beyond the discrete forecast period and the discount rate by: |
- |
Testing the source information underlying the determination of the long-term growth rate and discount rate, and the mathematical accuracy of the calculations. |
- |
Developing a range of independent estimates and comparing those to the long-term growth rate and discount rate selected by management. |
December 31, |
||||||||
2020 |
2019 |
|||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ |
$ |
||||||
Restricted cash |
||||||||
Accounts receivable – trade, net of allowance for doubtful accounts of $ |
||||||||
Accounts receivable – related parties |
||||||||
Inventories |
||||||||
Derivative assets (see Note 14) |
||||||||
Prepaid and other current assets |
||||||||
Total current assets |
||||||||
Property, plant and equipment, net |
||||||||
Investments in unconsolidated affiliates |
||||||||
Intangible assets, net of accumulated amortization of $ December 31, 2020 and $ |
||||||||
Goodwill (see Note 6) |
||||||||
Other assets |
||||||||
Total assets |
$ |
$ |
||||||
LIABILITIES AND EQUITY |
||||||||
Current liabilities: |
||||||||
Current maturities of debt (see Note 7) |
$ |
$ |
||||||
Accounts payable – trade |
||||||||
Accounts payable – related parties |
||||||||
Accrued product payables |
||||||||
Accrued interest |
||||||||
Derivative liabilities (see Note 14) |
||||||||
Other current liabilities |
||||||||
Total current liabilities |
||||||||
Long-term debt (see Note 7) |
||||||||
Deferred tax liabilities (see Note 16) |
||||||||
Other long-term liabilities |
||||||||
Commitments and contingent liabilities (see Note 17) |
||||||||
Redeemable preferred limited partner interests: (see Note 8) |
||||||||
Series A cumulative convertible preferred units (“preferred units”) ( |
||||||||
Equity: (see Note 8) |
||||||||
Partners’ equity: |
||||||||
Common limited partner interests ( |
||||||||
Treasury units, at cost |
( |
) |
||||||
Accumulated other comprehensive income (loss) |
( |
) |
||||||
Total partners’ equity |
||||||||
Noncontrolling interests in consolidated subsidiaries |
||||||||
Total equity |
||||||||
Total liabilities, preferred units, and equity |
$ |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Revenues: |
||||||||||||
Third parties |
$ |
$ |
$ |
|||||||||
Related parties |
||||||||||||
Total revenues (see Note 9) |
||||||||||||
Costs and expenses: |
||||||||||||
Operating costs and expenses: |
||||||||||||
Third party and other costs |
||||||||||||
Related parties |
||||||||||||
Total operating costs and expenses |
||||||||||||
General and administrative costs: |
||||||||||||
Third party and other costs |
||||||||||||
Related parties |
||||||||||||
Total general and administrative costs |
||||||||||||
Total costs and expenses (see Note 10) |
||||||||||||
Equity in income of unconsolidated affiliates |
||||||||||||
Operating income |
||||||||||||
Other income (expense): |
||||||||||||
Interest expense |
( |
) |
( |
) |
( |
) |
||||||
Change in fair market value of Liquidity Option (see Note 17) |
( |
) |
( |
) |
( |
) |
||||||
Gain on step acquisition of unconsolidated affiliate (see Note 12) |
||||||||||||
Interest income |
||||||||||||
Other, net |
||||||||||||
Total other expense, net |
( |
) |
( |
) |
( |
) |
||||||
Income before income taxes |
||||||||||||
Benefit from (provision for) income taxes (see Note 16) |
( |
) |
( |
) |
||||||||
Net income |
||||||||||||
Net income attributable to noncontrolling interests (see Note 8) |
( |
) |
( |
) |
( |
) |
||||||
Net income attributable to preferred units (see Note 8) |
( |
) |
||||||||||
Net income attributable to common unitholders |
$ |
$ |
$ |
|||||||||
Earnings per unit: (see Note 11) |
||||||||||||
Basic earnings per common unit |
$ |
$ |
$ |
|||||||||
Diluted earnings per common unit |
$ |
$ |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Net income |
$ |
$ |
$ |
|||||||||
Other comprehensive income (loss): |
||||||||||||
Cash flow hedges: (see Note 14) |
||||||||||||
Commodity hedging derivative instruments: |
||||||||||||
Changes in fair value of cash flow hedges |
||||||||||||
Reclassification of gains to net income |
( |
) |
( |
) |
( |
) |
||||||
Interest rate hedging derivative instruments: |
||||||||||||
Changes in fair value of cash flow hedges |
( |
) |
||||||||||
Reclassification of losses to net income |
||||||||||||
Total cash flow hedges |
( |
) |
||||||||||
Other |
( |
) |
( |
) |
( |
) |
||||||
Total other comprehensive income (loss) |
( |
) |
||||||||||
Comprehensive income |
||||||||||||
Comprehensive income attributable to noncontrolling interests |
( |
) |
( |
) |
( |
) |
||||||
Comprehensive income attributable to preferred units (see Note 8) |
( |
) |
||||||||||
Comprehensive income attributable to common unitholders |
$ |
$ |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Operating activities: |
||||||||||||
Net income |
$ |
$ |
$ |
|||||||||
Reconciliation of net income to net cash flows provided by operating activities: |
||||||||||||
Depreciation, amortization and accretion |
||||||||||||
Impairment of goodwill (see Notes 2 and 6) |
||||||||||||
Impairment of assets other than goodwill (see Notes 2 and 4) |
||||||||||||
Equity in income of unconsolidated affiliates |
( |
) |
( |
) |
( |
) |
||||||
Distributions received from unconsolidated affiliates attributable to earnings |
||||||||||||
Net gains attributable to asset sales (see Note 19) |
( |
) |
( |
) |
( |
) |
||||||
Deferred income tax expense (benefit) |
( |
) |
||||||||||
Change in fair market value of derivative instruments |
( |
) |
||||||||||
Change in fair market value of Liquidity Option (see Note 17) |
||||||||||||
Gain on step acquisition of unconsolidated affiliate (see Note 12) |
( |
) |
||||||||||
Non-cash expense related to long-term operating leases (see Note 17) |
||||||||||||
Net effect of changes in operating accounts (see Note 19) |
( |
) |
( |
) |
||||||||
Other operating activities |
( |
) |
||||||||||
Net cash flows provided by operating activities |
||||||||||||
Investing activities: |
||||||||||||
Capital expenditures |
( |
) |
( |
) |
( |
) |
||||||
Cash used for business combinations, net of cash received (see Note 12) |
( |
) |
||||||||||
Investments in unconsolidated affiliates |
( |
) |
( |
) |
( |
) |
||||||
Distributions received from unconsolidated affiliates attributable to the return of capital |
||||||||||||
Proceeds from asset sales (see Note 19) |
||||||||||||
Other investing activities |
( |
) |
( |
) |
( |
) |
||||||
Cash used in investing activities |
( |
) |
( |
) |
( |
) |
||||||
Financing activities: |
||||||||||||
Borrowings under debt agreements |
||||||||||||
Repayments of debt |
( |
) |
( |
) |
( |
) |
||||||
Debt issuance costs |
( |
) |
( |
) |
( |
) |
||||||
Monetization of interest rate derivative instruments (see Note 14) |
( |
) |
||||||||||
Cash distributions paid to common unitholders (see Note 8) |
( |
) |
( |
) |
( |
) |
||||||
Cash payments made in connection with distribution equivalent rights |
( |
) |
( |
) |
( |
) |
||||||
Cash distributions paid to noncontrolling interests (see Note 8) |
( |
) |
( |
) |
( |
) |
||||||
Cash contributions from noncontrolling interests (see Note 8) |
||||||||||||
Net cash proceeds from the issuance of common units |
||||||||||||
Repurchase of common units under buyback programs (see Note 8) |
( |
) |
( |
) |
( |
) |
||||||
Net cash proceeds from the issuance of preferred units (see Note 8) |
||||||||||||
Other financing activities |
( |
) |
( |
) |
( |
) |
||||||
Cash used in financing activities |
( |
) |
( |
) |
( |
) |
||||||
Net change in cash and cash equivalents, including restricted cash |
( |
) |
||||||||||
Cash and cash equivalents, including restricted cash, January 1 |
||||||||||||
Cash and cash equivalents, including restricted cash, December 31 |
$ |
$ |
$ |
Partners’ Equity |
||||||||||||||||||||
Common Limited Partner Interests |
Treasury Units |
Accumulated Other Comprehensive Income (Loss) |
Noncontrolling Interests in Consolidated Subsidiaries |
Total |
||||||||||||||||
Balance, December 31, 2017 |
$ |
$ |
$ |
( |
) |
$ |
$ |
|||||||||||||
Net income |
||||||||||||||||||||
Cash distributions paid to common unitholders |
( |
) |
( |
) |
||||||||||||||||
Cash payments made in connection with distribution equivalent rights |
( |
) |
( |
) |
||||||||||||||||
Cash distributions paid to noncontrolling interests |
( |
) |
( |
) |
||||||||||||||||
Cash contributions from noncontrolling interests |
||||||||||||||||||||
Net cash proceeds from the issuance of common units |
||||||||||||||||||||
Common units issued in connection with employee compensation |
||||||||||||||||||||
Common units issued in connection with land acquisition |
||||||||||||||||||||
Repurchase and cancellation of common units under Legacy Buyback Program |
( |
) |
( |
) |
||||||||||||||||
Amortization of fair value of equity-based awards |
||||||||||||||||||||
Cash flow hedges |
||||||||||||||||||||
Other, net |
( |
) |
( |
) |
( |
) |
( |
) |
||||||||||||
Balance, December 31, 2018 |
||||||||||||||||||||
Net income |
||||||||||||||||||||
Cash distributions paid to common unitholders |
( |
) |
( |
) |
||||||||||||||||
Cash payments made in connection with distribution equivalent rights |
( |
) |
( |
) |
||||||||||||||||
Cash distributions paid to noncontrolling interests |
( |
) |
( |
) |
||||||||||||||||
Cash contributions from noncontrolling interests |
||||||||||||||||||||
Net cash proceeds from the issuance of common units |
||||||||||||||||||||
Common units issued in connection with employee compensation |
||||||||||||||||||||
Repurchase and cancellation of common units under 2019 Buyback Program |
( |
) |
( |
) |
||||||||||||||||
Amortization of fair value of equity-based awards |
||||||||||||||||||||
Cash flow hedges |
||||||||||||||||||||
Other, net |
( |
) |
( |
) |
( |
) |
||||||||||||||
Balance, December 31, 2019 |
||||||||||||||||||||
Net income |
||||||||||||||||||||
Cash distributions paid to common unitholders |
( |
) |
( |
) |
||||||||||||||||
Cash payments made in connection with distribution equivalent rights |
( |
) |
( |
) |
||||||||||||||||
Cash distributions paid to noncontrolling interests |
( |
) |
( |
) |
||||||||||||||||
Cash contributions from noncontrolling interests |
||||||||||||||||||||
Repurchase and cancellation of common units under 2019 Buyback Program |
( |
) |
( |
) |
||||||||||||||||
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option (see Note 8) |
||||||||||||||||||||
Treasury units acquired in connection with settlement of Liquidity Option, at cost (see Note 8) |
( |
) |
( |
) |
||||||||||||||||
Common units exchanged for preferred units, with common units received being immediately cancelled (see Note 8) |
( |
) |
( |
) |
||||||||||||||||
Amortization of fair value of equity-based awards |
||||||||||||||||||||
Cash flow hedges |
( |
) |
( |
) |
||||||||||||||||
Other, net |
( |
) |
( |
) |
( |
) |
||||||||||||||
Balance, December 31, 2020 |
$ |
$ |
( |
) |
$ |
( |
) |
$ |
$ |
• |
natural gas gathering, treating, processing, transportation and storage; |
• |
NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases, or “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; and |
• |
a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Balance at beginning of period |
$ |
$ |
$ |
|||||||||
Charged to costs and expenses |
||||||||||||
Charged to other accounts (1) |
||||||||||||
Deductions |
( |
) |
( |
) |
( |
) |
||||||
Balance at end of period |
$ |
$ |
$ |
(1) |
December 31, |
||||||||
2020 |
2019 |
|||||||
Cash and cash equivalents |
$ |
$ |
||||||
Restricted cash |
||||||||
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows |
$ |
$ |
• | Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change. |
• | Variable cash flows of a forecasted transaction – In a cash flow hedge, the change in the fair value of the hedge is reported in other comprehensive income (loss) and is reclassified to earnings when the forecasted transaction affects earnings. |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Balance at beginning of period |
$ |
$ |
$ |
|||||||||
Charged to costs and expenses |
||||||||||||
Acquisition-related additions and other |
||||||||||||
Deductions |
( |
) |
( |
) |
( |
) |
||||||
Balance at end of period |
$ |
$ |
$ |
• | 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”)). 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 swap settlements. |
• | 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, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Impairment charges reflected in operating costs and expenses: |
||||||||||||
Property, plant and equipment (see Note 4) |
$ |
$ |
$ |
|||||||||
Investment in unconsolidated affiliate (see Note 5) |
||||||||||||
Goodwill (see Note 6) |
||||||||||||
Other (1) |
||||||||||||
Total asset impairment charges in operating costs and expenses |
||||||||||||
Other property, plant and equipment impairment charges (2) |
||||||||||||
Total asset impairment charges |
$ |
$ |
$ |
(1) |
Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill. |
(2) |
• | 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. See Note 5 for information regarding an impairment charge attributable to our investments in unconsolidated affiliates in 2019. |
• | 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 Impairment,” the provisions of which we adopted on January 1, 2020. Goodwill impairment charges represent the amount by which a reporting unit’s carrying value (including its respective goodwill) exceeds its fair value, not to exceed the carrying amount of the reporting unit’s goodwill. |
• | We do not recognize ROU assets and lease liabilities for short-term leases and instead record them in a manner similar to operating leases under legacy lease accounting guidelines. A short term lease is one with a maximum lease term of 12 months or less and does not include a purchase option the lessee is reasonably certain to exercise. |
• | We did not reassess whether any expired or existing contracts as of January 1, 2019 contained leases or the lease classification for any such existing or expired leases. |
• | The impact of adopting ASC 842 was prospective beginning January 1, 2019. We did not recast prior periods presented in our consolidated financial statements to reflect the new lease accounting guidance. |
• | We combine lease and nonlease components relating to our office and warehouse leases, as applicable. |
December 31, |
||||||||
2020 |
2019 |
|||||||
NGLs |
$ |
$ |
||||||
Petrochemicals and refined products |
||||||||
Crude oil |
||||||||
Natural gas |
||||||||
Total |
$ |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Cost of sales (1) |
$ |
$ |
$ |
|||||||||
Lower of cost or net realizable value adjustments recognized in cost of sales |
(1) |
Estimated Useful Life |
December 31, |
|||||||||||
in Years |
2020 |
2019 |
||||||||||
Plants, pipelines and facilities (1) |
(5) |
$ |
$ |
|||||||||
Underground and other storage facilities (2) |
(6) |
|||||||||||
Transportation equipment (3) |
||||||||||||
Marine vessels (4) |
||||||||||||
Land |
||||||||||||
Construction in progress |
||||||||||||
Total |
||||||||||||
Less accumulated depreciation |
||||||||||||
Property, plant and equipment, net |
$ |
$ |
(1) |
|
(2) |
|
(3) |
|
(4) |
|
(5) |
|
(6) |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Depreciation expense (1) |
$ |
$ |
$ |
|||||||||
Capitalized interest (2) |
(1) |
|
(2) |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
ARO liability beginning balance |
$ |
$ |
$ |
|||||||||
Liabilities incurred |
||||||||||||
Liabilities settled |
( |
) |
( |
) |
( |
) |
||||||
Revisions in estimated cash flows |
( |
) |
||||||||||
Accretion expense |
||||||||||||
ARO liability ending balance |
$ |
$ |
$ |
2021 |
2022 |
2023 |
2024 |
2025 |
||||||||||||||
$ |
$ |
$ |
$ |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
NGL Pipelines & Services: |
||||||||||||
South Texas natural gas processing plants |
$ |
$ |
||||||||||
Other |
$ |
|||||||||||
Crude Oil Pipelines & Services: |
||||||||||||
Cancellation of Midland-to-ECHO 4 project |
||||||||||||
Other |
||||||||||||
Natural Gas Pipelines & Services: |
||||||||||||
South Texas natural gas gathering pipelines |
||||||||||||
Other |
||||||||||||
Petrochemical & Refined Products Services: |
||||||||||||
Marine transportation business |
||||||||||||
Other |
||||||||||||
Total impairment charges for property, plant and equipment |
$ |
$ |
$ |
• | In December 2020, we evaluated our marine transportation business for impairment due to a lower demand outlook for such services. As a result of our review, we recognized an impairment charge of $ |
• | In December 2020, we evaluated certain of our natural gas gathering and processing assets in South Texas for impairment due to a lower production outlook. As a result of our review, we recognized an aggregate impairment charge of $ |
• | In September 2020, we recognized $ |
• | The remainder of our impairment charges for 2020 (i.e., those classified as “Other” in the preceding table) are attributable to the complete write-off of assets that are no longer expected to be used or constructed. |
Ownership Interest at December 31, |
December 31, |
||||||
2020 |
2020 |
2019 |
|||||
NGL Pipelines & Services: |
|||||||
Venice Energy Service Company, L.L.C. (“VESCO”) |
$ |
$ |
|||||
K/D/S Promix, L.L.C. (“Promix”) |
|||||||
Baton Rouge Fractionators LLC (“BRF”) |
|||||||
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) |
|||||||
Texas Express Pipeline LLC (“Texas Express”) |
|||||||
Texas Express Gathering LLC (“TEG”) |
|||||||
Front Range Pipeline LLC (“Front Range”) |
|||||||
Crude Oil Pipelines & Services: |
|||||||
Seaway Crude Holdings LLC (“Seaway”) |
|||||||
Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) |
|||||||
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) |
|||||||
Natural Gas Pipelines & Services: |
|||||||
White River Hub, LLC (“White River Hub”) |
|||||||
Old Ocean Pipeline, LLC (“Old Ocean”) |
|||||||
Petrochemical & Refined Products Services: |
|||||||
Baton Rouge Propylene Concentrator LLC (“BRPC”) |
|||||||
Transport 4, LLC (“Transport 4”) |
|||||||
Total |
$ |
$ |
• | VESCO owns the Venice natural gas processing facility and a related gathering system located in south Louisiana. |
• | Promix owns an NGL fractionation facility and a related gathering system located in south Louisiana. |
• | BRF owns an NGL fractionation facility located in south Louisiana. |
• | Skelly-Belvieu owns a pipeline that transports mixed NGLs from Skellytown, Texas to Mont Belvieu, Texas. |
• | Texas Express owns an NGL pipeline that extends from Skellytown to our Mont Belvieu NGL fractionation and storage complex. Mixed NGLs from the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown. In addition, mixed NGLs from the Denver-Julesburg (“DJ”) Basin in Colorado are delivered to the Texas Express Pipeline via an interconnect with the Front Range Pipeline near Skellytown. The Texas Express Pipeline is also used to transport mixed NGLs gathered by TEG to Mont Belvieu. |
• | TEG owns two NGL gathering systems that deliver mixed NGLs to the Texas Express Pipeline. |
• | Front Range owns an NGL pipeline that transports mixed NGLs from natural gas processing facilities located in the DJ Basin to an interconnect with our Texas Express Pipeline and Mid-America Pipeline System and other third party facilities near Skellytown. |
• | Seaway owns a crude oil pipeline system that connects the Cushing, Oklahoma hub, which is a major industry trading hub and price settlement point for West Texas Intermediate on the NYMEX, with markets in Southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System. |
• | Eagle Ford Crude Oil Pipeline owns a pipeline that transports crude oil and condensate for producers in South Texas. The system originates in Gardendale, Texas and extends to Three Rivers, Texas and further to Corpus Christi, Texas. The system interconnects with our South Texas Crude Oil Pipeline System and a marine terminal owned by Eagle Ford Corpus Christi. |
• | Eagle Ford Corpus Christi owns a marine crude oil terminal located in Corpus Christi, Texas that can load ocean-going vessels with either crude oil or condensate. |
• | White River Hub owns a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado. |
• | Old Ocean owns a natural gas pipeline that extends from near Maypearl, Texas to Sweeny, Texas. |
• | BRPC owns a propylene fractionation facility located in south Louisiana. |
• | Transport 4 provides pipeline and terminal logistics services used by our refined products pipelines. |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
NGL Pipelines & Services |
$ |
$ |
$ |
|||||||||
Crude Oil Pipelines & Services |
||||||||||||
Natural Gas Pipelines & Services |
||||||||||||
Petrochemical & Refined Products Services (1) |
( |
) |
( |
) |
( |
) |
||||||
Total |
$ |
$ |
$ |
(1) |
The losses recorded for this segment are primarily due to protection, maintenance and pipeline integrity costs of the idled Centennial Pipeline, which was purged and filled with nitrogen in 2013. |
December 31, 2020 |
December 31, 2019 |
|||||||||||||||||||||||
Gross Value |
Accumulated Amortization |
Carrying Value |
Gross Value |
Accumulated Amortization |
Carrying Value |
|||||||||||||||||||
NGL Pipelines & Services: |
||||||||||||||||||||||||
Customer relationship intangibles |
$ |
$ |
( |
) |
$ |
$ |
$ |
( |
) |
$ |
||||||||||||||
Contract-based intangibles |
( |
) |
( |
) |
||||||||||||||||||||
Segment total |
( |
) |
( |
) |
||||||||||||||||||||
Crude Oil Pipelines & Services: |
||||||||||||||||||||||||
Customer relationship intangibles |
( |
) |
( |
) |
||||||||||||||||||||
Contract-based intangibles |
( |
) |
( |
) |
||||||||||||||||||||
Segment total |
( |
) |
( |
) |
||||||||||||||||||||
Natural Gas Pipelines & Services: |
||||||||||||||||||||||||
Customer relationship intangibles |
( |
) |
( |
) |
||||||||||||||||||||
Contract-based intangibles |
( |
) |
( |
) |
||||||||||||||||||||
Segment total |
( |
) |
( |
) |
||||||||||||||||||||
Petrochemical & Refined Products Services: |
||||||||||||||||||||||||
Customer relationship intangibles |
( |
) |
( |
) |
||||||||||||||||||||
Contract-based intangibles |
( |
) |
( |
) |
||||||||||||||||||||
Segment total |
( |
) |
( |
) |
||||||||||||||||||||
Total intangible assets |
$ |
$ |
( |
) |
$ |
$ |
$ |
( |
) |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
NGL Pipelines & Services |
$ |
$ |
$ |
|||||||||
Crude Oil Pipelines & Services |
||||||||||||
Natural Gas Pipelines & Services |
||||||||||||
Petrochemical & Refined Products Services |
||||||||||||
Total |
$ |
$ |
$ |
2021 |
2022 |
2023 |
2024 |
2025 |
||||||||||||||
$ |
$ |
$ |
$ |
$ |
a |
Weighted Average Remaining Amortization Period |
December 31, 2020 |
|||||||||
Gross Value |
Accumulated Amortization |
Carrying Value |
|||||||||
Basin-specific customer relationships: |
|||||||||||
EFS Midstream (acquired 2015) |
$ |
$ |
( |
$ |
|||||||
State Line and Fairplay (acquired 2010) |
( |
||||||||||
San Juan Gathering (acquired 2004) |
( |
||||||||||
General customer relationships: |
|||||||||||
Oiltanking (acquired 2014) |
( |
• | 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. |
• | The State Line and Fairplay customer relationships provide us with long-term access to natural gas producers served by our Haynesville and Fairplay Gathering Systems. The Haynesville Gathering System gathers and treats natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and East Texas. The Fairplay Gathering System gathers natural gas produced from the Cotton Valley formation in East Texas. |
• | The San Juan Gathering customer relationships provide us with long-term access to natural gas producers in the San Juan Basin served by our San Juan Gathering System. |
• | The Oiltanking customer relationships provide us with long-term access to crude oil and refined products storage and terminal customers served at our Houston Ship Channel and Beaumont, Texas terminals. |
a |
Weighted Average Remaining Amortization Period |
December 31, 2020 |
|||||||||
Gross Value |
Accumulated Amortization |
Carrying Value |
|||||||||
Oiltanking customer contracts |
$ |
$ |
( |
$ |
|||||||
Jonah natural gas gathering agreements |
( |
||||||||||
Delaware Basin natural gas processing contracts |
( |
• | The Oiltanking customer contracts represent the estimated value we assigned to crude oil storage and terminal agreements we acquired in 2014 associated with our Houston and Beaumont marine terminals. Amortization expense attributable to these contracts is recorded using a straight-line approach over the terms of the underlying contracts. |
• | The Jonah natural gas gathering agreements represent the estimated value we assigned to natural gas gathering contracts acquired in 2001 associated with the Jonah Gathering System. Amortization expense attributable to these intangible assets is recorded using a units-of-production method based on gathering volumes. |
• | The Delaware Basin natural gas processing contracts represent the estimated value we assigned to natural gas processing contracts we acquired in March 2018 in connection with our step acquisition of the remaining 50% member interest in Delaware Basin Gas Processing LLC (“Delaware Processing”) (see Note 12). Amortization expense attributable to these contracts is recorded using a straight-line approach over the terms of the underlying contracts. |
NGL Pipelines & Services |
Crude Oil Pipelines & Services |
Natural Gas Pipelines & Services |
Petrochemical & Refined Products Services |
Consolidated Total |
||||||||||||||||
Balance at December 31, 2018 |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||
Balance at December 31, 2019 |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||
Impairment of goodwill |
( |
) |
( |
) |
||||||||||||||||
Balance at December 31, 2020 |
$ |
$ |
$ |
$ |
$ |
December 31, |
||||||||
2020 |
2019 |
|||||||
EPO senior debt obligations: |
||||||||
Commercial Paper Notes, variable-rates |
$ |
$ |
||||||
Senior Notes Q, |
||||||||
Senior Notes Y, |
||||||||
Senior Notes TT, |
||||||||
Senior Notes RR, |
||||||||
September 2020 364-Day Revolving Credit Agreement, variable-rate, due September 2021 |
||||||||
Senior Notes VV, |
||||||||
Senior Notes CC, |
||||||||
Senior Notes HH, |
||||||||
Senior Notes JJ, |
||||||||
Multi-Year Revolving Credit Agreement, variable-rate, due September 2024 |
||||||||
Senior Notes MM, |
||||||||
Senior Notes PP, |
||||||||
Senior Notes SS, |
||||||||
Senior Notes WW, |
||||||||
Senior Notes YY, |
||||||||
Senior Notes AAA, |
||||||||
Senior Notes D, |
||||||||
Senior Notes H, |
||||||||
Senior Notes J, |
||||||||
Senior Notes W, |
||||||||
Senior Notes R, |
||||||||
Senior Notes Z, |
||||||||
Senior Notes BB, |
||||||||
Senior Notes DD, |
||||||||
Senior Notes EE, |
||||||||
Senior Notes GG, |
||||||||
Senior Notes II, |
||||||||
Senior Notes KK, |
||||||||
Senior Notes QQ, |
||||||||
Senior Notes UU, |
||||||||
Senior Notes XX, |
||||||||
Senior Notes ZZ, |
||||||||
Senior Notes BBB, |
||||||||
Senior Notes DDD, |
||||||||
Senior Notes NN, |
||||||||
Senior Notes CCC, |
||||||||
TEPPCO senior debt obligations: |
||||||||
TEPPCO Senior Notes, |
||||||||
Total principal amount of senior debt obligations |
||||||||
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1) |
||||||||
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (2) |
||||||||
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (3) |
||||||||
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (4) |
||||||||
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1) |
||||||||
Total principal amount of senior and junior debt obligations |
||||||||
Other, non-principal amounts |
( |
) |
( |
) |
||||
Less current maturities of debt |
( |
) |
( |
) |
||||
Total long-term debt |
$ |
$ |
(1) |
|
(2) |
|
(3) |
|
(4) |
Range of Interest Rates Paid |
Weighted-Average Interest Rate Paid |
|
Commercial Paper Notes |
||
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes |
Scheduled Maturities of Debt |
||||||||||||||||||||||||||||
Total |
2021 |
2022 |
2023 |
2024 |
2025 |
Thereafter |
||||||||||||||||||||||
Senior Notes |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Junior Subordinated Notes |
||||||||||||||||||||||||||||
Total |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
Common units outstanding at December 31, 2017 |
||||
Common unit repurchases under Legacy Buyback Program |
( |
) |
||
Common units issued in connection with DRIP and EUPP |
||||
Common units issued in connection with the vesting of phantom unit awards, net |
||||
Common units issued in connection with employee compensation |
||||
Common units issued in connection with land acquisition |
||||
Other |
||||
Common units outstanding at December 31, 2018 |
||||
Common unit repurchases under 2019 Buyback Program |
( |
) |
||
Common units issued in connection with DRIP and EUPP |
||||
Common units issued in connection with the vesting of phantom unit awards, net |
||||
Common units issued in connection with employee compensation |
||||
Other |
||||
Common units outstanding at December 31, 2019 |
||||
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option in March 2020 |
||||
Treasury units acquired in connection with settlement of the Liquidity Option in March 2020 |
( |
) |
||
Common unit repurchases under 2019 Buyback Program |
( |
) |
||
Common units issued in connection with the vesting of phantom unit awards, net |
||||
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled |
( |
) |
||
Other |
||||
Common units outstanding at December 31, 2020 |
Original issuance of preferred units on September 30, 2020: |
||||
Units sold to third party purchasers |
||||
Units sold to a related party |
||||
Total preferred units outstanding at September 30, 2020 |
||||
Paid-in kind distribution to related party |
||||
Preferred units outstanding at December 31, 2020 |
• |
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 |
• |
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) $ |
• |
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: |
• |
$ |
• |
$ |
• |
$ |
• |
$ |
• |
$ |
• |
if a Change of Control event occurs prior to September 30, 2026, the redemption price is $ |
Cash Flow Hedges |
||||||||||||||||
Commodity Derivative Instruments |
Interest Rate Derivative Instruments |
Other |
Total |
|||||||||||||
Accumulated Other Comprehensive Income (Loss), December 31, 2018 |
$ |
$ |
( |
) |
$ |
$ |
||||||||||
Other comprehensive income (loss) for period, before reclassifications |
( |
) |
||||||||||||||
Reclassification of losses (gains) to net income during period |
( |
) |
( |
) |
||||||||||||
Total other comprehensive income (loss) for period |
( |
) |
( |
) |
||||||||||||
Accumulated Other Comprehensive Income (Loss), December 31, 2019 |
||||||||||||||||
Other comprehensive income (loss) for period, before reclassifications |
( |
) |
( |
) |
( |
) |
||||||||||
Reclassification of losses (gains) to net income during period |
( |
) |
( |
) |
||||||||||||
Total other comprehensive income (loss) for period |
( |
) |
( |
) |
( |
) |
( |
) |
||||||||
Accumulated Other Comprehensive Income (Loss), December 31, 2020 |
$ |
( |
) |
$ |
( |
) |
$ |
$ |
( |
) |
For the Year Ended December 31, |
|||||||||
Losses (gains) on cash flow hedges: |
Location |
2020 |
2019 |
||||||
Interest rate derivatives |
Interest expense |
$ |
$ |
||||||
Commodity derivatives |
Revenue |
( |
) |
( |
) |
||||
Commodity derivatives |
Operating costs and expenses |
||||||||
Total |
$ |
( |
) |
$ |
( |
) |
At December 31, |
||||||||
Consolidated Subsidiary |
2020 |
2019 |
||||||
Breviloba LLC (“Breviloba”)(1) |
$ |
$ |
||||||
Whitethorn Pipeline Company LLC (“Whitethorn”)(2) |
||||||||
Enterprise Navigator Ethylene Terminal LLC (“ENET”)(3) |
||||||||
Other (4) |
||||||||
Total noncontrolling interests in consolidated subsidiaries |
$ |
$ |
(1) |
|
(2) |
|
(3) |
|
(4) |
Quarterly Distribution Per Common Unit |
Record Date |
Payment Date |
||||
2018: |
||||||
1st Quarter |
$ |
|||||
2nd Quarter |
$ |
|||||
3rd Quarter |
$ |
|||||
4th Quarter |
$ |
|||||
2019: |
||||||
1st Quarter |
$ |
|||||
2nd Quarter |
$ |
|||||
3rd Quarter |
$ |
|||||
4th Quarter |
$ |
|||||
2020: |
||||||
1st Quarter |
$ |
|||||
2nd Quarter |
$ |
|||||
3rd Quarter |
$ |
|||||
4th Quarter |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
NGL Pipelines & Services: |
||||||||||||
Sales of NGLs and related products |
$ |
$ |
$ |
|||||||||
Segment midstream services: |
||||||||||||
Natural gas processing and fractionation |
||||||||||||
Transportation |
||||||||||||
Storage and terminals |
||||||||||||
Total segment midstream services |
||||||||||||
Total NGL Pipelines & Services |
||||||||||||
Crude Oil Pipelines & Services: |
||||||||||||
Sales of crude oil |
||||||||||||
Segment midstream services: |
||||||||||||
Transportation |
||||||||||||
Storage and terminals |
||||||||||||
Total segment midstream services |
||||||||||||
Total Crude Oil Pipelines & Services |
||||||||||||
Natural Gas Pipelines & Services: |
||||||||||||
Sales of natural gas |
||||||||||||
Segment midstream services: |
||||||||||||
Transportation |
||||||||||||
Total segment midstream services |
||||||||||||
Total Natural Gas Pipelines & Services |
||||||||||||
Petrochemical & Refined Products Services: |
||||||||||||
Sales of petrochemicals and refined products |
||||||||||||
Segment midstream services: |
||||||||||||
Fractionation and isomerization |
||||||||||||
Transportation, including marine logistics |
||||||||||||
Storage and terminals |
||||||||||||
Total segment midstream services |
||||||||||||
Total Petrochemical & Refined Products Services |
||||||||||||
Total consolidated revenues |
$ |
$ |
$ |
December 31, |
|||||||||
Contract Asset |
Location |
2020 |
2019 |
||||||
Unbilled revenue (current amount) |
Prepaid and other current assets |
$ |
$ |
||||||
Total |
$ |
$ |
December 31, |
|||||||||
Contract Liability |
Location |
2020 |
2019 |
||||||
Deferred revenue (current amount) |
Other current liabilities |
$ |
$ |
||||||
Deferred revenue (noncurrent) |
Other long-term liabilities |
||||||||
Total |
$ |
$ |
Unbilled Revenue |
Deferred Revenue |
|||||||
Balance at January 1, 2018 (upon adoption of ASC 606) |
$ |
$ |
||||||
Amount included in opening balance transferred to other accounts during period (1) |
( |
) |
||||||
Amount recorded during period (2) |
||||||||
Amounts recorded during period transferred to other accounts (1) |
( |
) |
( |
) |
||||
Amount recorded in connection with business combination |
||||||||
Other changes |
( |
) |
||||||
Balance at December 31, 2018 |
$ |
$ |
||||||
Amount included in opening balance transferred to other accounts during period (1) |
( |
) |
( |
) |
||||
Amount recorded during period (2) |
||||||||
Amounts recorded during period transferred to other accounts (1) |
( |
) |
( |
) |
||||
Other changes |
( |
) |
||||||
Balance at December 31, 2019 |
$ |
$ |
||||||
Amount included in opening balance transferred to other accounts during period (1) |
( |
) |
( |
) |
||||
Amount recorded during period (2) |
||||||||
Amounts recorded during period transferred to other accounts (1) |
( |
) |
( |
) |
||||
Other changes |
( |
) |
||||||
Balance at December 31, 2020 |
$ |
$ |
(1) |
|
(2) |
Period |
Fixed Consideration |
|||
$ |
||||
Thereafter |
||||
Total |
$ |
• | Our NGL Pipelines & Services business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals. |
• | Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities. |
• | Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities. |
• |
Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and a PDH facility, and related pipelines and marketing activities, (ii) butane isomerization complex and related deisobutanizer (“DIB”) operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) an ethylene export terminal and related operations; and (vi) marine transportation business. |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Operating income |
$ |
$ |
$ |
|||||||||
Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign): |
||||||||||||
Depreciation, amortization and accretion expense in operating costs and expenses |
||||||||||||
Asset impairment and related charges in operating costs and expenses |
||||||||||||
Net gains attributable to asset sales in operating costs and expenses |
( |
) |
( |
) |
( |
) |
||||||
General and administrative costs |
||||||||||||
Non-refundable payments received from shippers attributable to make-up rights (1) |
||||||||||||
Subsequent recognition of revenues attributable to make-up rights (2) |
( |
) |
( |
) |
( |
) |
||||||
Total segment gross operating margin |
$ |
$ |
$ |
(1) |
|
(2) |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Gross operating margin by segment: |
||||||||||||
NGL Pipelines & Services |
$ |
$ |
$ |
|||||||||
Crude Oil Pipelines & Services |
||||||||||||
Natural Gas Pipelines & Services |
||||||||||||
Petrochemical & Refined Products Services |
||||||||||||
Total segment gross operating margin |
$ |
$ |
$ |
Reportable Business Segments |
||||||||||||||||||||||||
NGL Pipelines & Services |
Crude Oil Pipelines & Services |
Natural Gas Pipelines & Services |
Petrochemical & Refined Products Services |
Adjustments and Eliminations |
Consolidated Total |
|||||||||||||||||||
Revenues from third parties: |
||||||||||||||||||||||||
Year ended December 31, 2020 |
$ |
$ |
$ |
$ |
$ |
$ |
||||||||||||||||||
Year ended December 31, 2019 |
||||||||||||||||||||||||
Year ended December 31, 2018 |
||||||||||||||||||||||||
Revenues from related parties: |
||||||||||||||||||||||||
Year ended December 31, 2020 |
||||||||||||||||||||||||
Year ended December 31, 2019 |
||||||||||||||||||||||||
Year ended December 31, 2018 |
||||||||||||||||||||||||
Intersegment and intrasegment revenues: |
||||||||||||||||||||||||
Year ended December 31, 2020 |
( |
) |
||||||||||||||||||||||
Year ended December 31, 2019 |
( |
) |
||||||||||||||||||||||
Year ended December 31, 2018 |
( |
) |
||||||||||||||||||||||
Total revenues: |
||||||||||||||||||||||||
Year ended December 31, 2020 |
( |
) |
||||||||||||||||||||||
Year ended December 31, 2019 |
( |
) |
||||||||||||||||||||||
Year ended December 31, 2018 |
( |
) |
||||||||||||||||||||||
Equity in income (loss) of unconsolidated affiliates: |
||||||||||||||||||||||||
Year ended December 31, 2020 |
( |
) |
||||||||||||||||||||||
Year ended December 31, 2019 |
( |
) |
||||||||||||||||||||||
Year ended December 31, 2018 |
( |
) |
Reportable Business Segments |
||||||||||||||||||||||||
NGL Pipelines & Services |
Crude Oil Pipelines & Services |
Natural Gas Pipelines & Services |
Petrochemical & Refined Products Services |
Adjustments and Eliminations |
Consolidated Total |
|||||||||||||||||||
Property, plant and equipment, net: (see Note 4) |
||||||||||||||||||||||||
At December 31, 2020 |
$ |
$ |
$ |
$ |
$ |
$ |
||||||||||||||||||
At December 31, 2019 |
||||||||||||||||||||||||
At December 31, 2018 |
||||||||||||||||||||||||
Investments in unconsolidated affiliates: (see Note 5) |
||||||||||||||||||||||||
At December 31, 2020 |
||||||||||||||||||||||||
At December 31, 2019 |
||||||||||||||||||||||||
At December 31, 2018 |
||||||||||||||||||||||||
Intangible assets, net: (see Note 6) |
||||||||||||||||||||||||
At December 31, 2020 |
||||||||||||||||||||||||
At December 31, 2019 |
||||||||||||||||||||||||
At December 31, 2018 |
||||||||||||||||||||||||
Goodwill: (see Note 6) |
||||||||||||||||||||||||
At December 31, 2020 |
||||||||||||||||||||||||
At December 31, 2019 |
||||||||||||||||||||||||
At December 31, 2018 |
||||||||||||||||||||||||
Segment assets: |
||||||||||||||||||||||||
At December 31, 2020 |
||||||||||||||||||||||||
At December 31, 2019 |
||||||||||||||||||||||||
At December 31, 2018 |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Consolidated revenues: |
||||||||||||
NGL Pipelines & Services |
$ |
$ |
$ |
|||||||||
Crude Oil Pipelines & Services |
||||||||||||
Natural Gas Pipelines & Services |
||||||||||||
Petrochemical & Refined Products Services |
||||||||||||
Total consolidated revenues |
$ |
$ |
$ |
|||||||||
Consolidated costs and expenses: |
||||||||||||
Operating costs and expenses: |
||||||||||||
Cost of sales |
$ |
$ |
$ |
|||||||||
Other operating costs and expenses (1) |
||||||||||||
Depreciation, amortization and accretion |
||||||||||||
Impairment of goodwill |
||||||||||||
Impairment of assets other than goodwill |
||||||||||||
Net gains attributable to asset sales |
( |
) |
( |
) |
( |
) |
||||||
General and administrative costs |
||||||||||||
Total consolidated costs and expenses |
$ |
$ |
$ |
(1) |
NGL Pipelines & Services |
$ |
|||
Crude Oil Pipelines & Services |
||||
Natural Gas Pipelines & Services |
||||
Petrochemical & Refined Products Services |
||||
Total |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
BASIC EARNINGS PER COMMON UNIT |
||||||||||||
Net income attributable to common unitholders |
$ |
$ |
$ |
|||||||||
Earnings allocated to phantom unit awards (1) |
( |
) |
( |
) |
( |
) |
||||||
Net income allocated to common unitholders |
$ |
$ |
$ |
|||||||||
Basic weighted-average number of common units outstanding |
||||||||||||
Basic earnings per common unit |
$ |
$ |
$ |
|||||||||
DILUTED EARNINGS PER COMMON UNIT |
||||||||||||
Net income attributable to common unitholders |
$ |
$ |
$ |
|||||||||
Net income attributable to preferred units |
||||||||||||
Net income attributable to limited partners |
$ |
$ |
$ |
|||||||||
Diluted weighted-average number of units outstanding: |
||||||||||||
Distribution-bearing common units |
||||||||||||
Phantom units (2) |
||||||||||||
Preferred units (2) |
||||||||||||
Total |
||||||||||||
Diluted earnings per common unit |
$ |
$ |
$ |
(1) |
|
(2) |
Purchase price for remaining |
$ |
|||
Fair value of our |
||||
Total |
$ |
|||
Recognized amounts of identifiable assets acquired and liabilities assumed: |
||||
Assets acquired in business combination: |
||||
Current assets, including cash of $ |
$ |
|||
Property, plant and equipment |
||||
Contract-based intangible assets |
||||
Customer relationship intangible assets |
||||
Total assets acquired |
$ |
|||
Liabilities assumed in business combination: |
||||
Current liabilities |
$ |
( |
) |
|
Long-term liabilities |
( |
) |
||
Total liabilities assumed |
$ |
( |
) |
|
Total identifiable net assets |
$ |
|||
Goodwill |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Equity-classified awards: |
||||||||||||
Phantom unit awards |
$ |
$ |
$ |
|||||||||
Profits interest awards |
||||||||||||
Liability-classified awards |
||||||||||||
Total |
$ |
$ |
$ |
Number of Units |
Weighted- Average Grant Date Fair Value per Unit (1) |
|||||||
Phantom unit awards at December 31, 2017 |
$ |
|||||||
Granted (2) |
$ |
|||||||
Vested |
( |
) |
$ |
|||||
Forfeited |
( |
) |
$ |
|||||
Phantom unit awards at December 31, 2018 |
$ |
|||||||
Granted (3) |
$ |
|||||||
Vested |
( |
) |
$ |
|||||
Forfeited |
( |
) |
$ |
|||||
Phantom unit awards at December 31, 2019 |
$ |
|||||||
Granted (4) |
$ |
|||||||
Vested |
( |
) |
$ |
|||||
Forfeited |
( |
) |
$ |
|||||
Phantom unit awards at December 31, 2020 |
$ |
(1) |
|
(2) |
|
(3) |
|
(4) |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Cash payments made in connection with DERs |
$ |
$ |
$ |
|||||||||
Total intrinsic value of phantom unit awards that vested during period |
$ |
$ |
$ |
Employee Partnership |
Partnership Common Units Contributed by EPCO Holdings |
Class A Capital Base (1) |
Class A Preference Return |
Expected Vesting/ Liquidation Date |
Estimated Fair Value of Profits Interest Awards (2) |
Unrecognized Compensation Cost (3) |
PubCo II |
$ |
$ |
February 2023 |
$ |
$ |
|
PrivCo I |
$ |
$ |
February 2023 |
$ |
$ |
|
EPD IV |
$ |
$ |
December 2023 |
$ |
$ |
|
EPCO II |
$ |
$ |
December 2023 |
$ |
$ |
(1) |
|
(2) |
|
(3) |
Expected Life |
Risk-Free |
Expected |
Expected Unit |
|
Employee |
of Award |
Interest |
Distribution |
Price |
Partnership |
from Grant Date |
Rate |
Yield |
Volatility |
PubCo II |
||||
PrivCo I |
||||
EPD IV |
||||
EPCO II |
Hedged Transaction |
Number and Type of Derivatives Outstanding |
Notional Amount |
Expected Settlement Date |
Weighted-Average Fixed Rate Locked |
Accounting Treatment |
Future long-term debt offering |
$ |
4/2021 |
Cash flow hedge |
||
Future long-term debt offering |
$ |
4/2021 |
Cash flow hedge |
||
Future long-term debt offering |
$ |
2/2022 |
Cash flow hedge |
||
Future long-term debt offering |
$ |
4/2021 |
Cash flow hedge |
||
Future long-term debt offering |
$ |
2/2022 |
Cash flow hedge |
||
Future long-term debt offering |
$ |
2/2022 |
Cash flow hedge |
(1) |
• | 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 NGL production using derivative instruments and related contracts. For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for shrinkage, which is hedged using derivative instruments and related contracts. |
• | 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. |
Volume (1) |
Accounting |
||||
Derivative Purpose |
Current (2) |
Long-Term (2) |
Treatment |
||
Derivatives designated as hedging instruments: |
|||||
Natural gas processing: |
|||||
Forecasted natural gas purchases for plant thermal reduction (Bcf) |
n/a |
Cash flow hedge |
|||
Forecasted sales of NGLs (MMBbls) |
n/a |
Cash flow hedge |
|||
Natural gas marketing: |
|||||
Natural gas storage inventory management activities (Bcf) |
n/a |
Fair value hedge |
|||
NGL marketing: |
|||||
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) |
Cash flow hedge |
||||
Forecasted sales of NGLs and related hydrocarbon products (MMBbls) |
Cash flow hedge |
||||
NGLs inventory management activities (MMBbls) |
n/a |
Fair value hedge |
|||
Refined products marketing: |
|||||
Forecasted purchases of refined products (MMBbls) |
n/a |
Cash flow hedge |
|||
Forecasted sales of refined products (MMBbls) |
Cash flow hedge |
||||
Refined products inventory management activities (MMBbls) |
n/a |
Fair value hedge |
|||
Crude oil marketing: |
|||||
Forecasted purchases of crude oil (MMBbls) |
n/a |
Cash flow hedge |
|||
Forecasted sales of crude oil (MMBbls) |
n/a |
Cash flow hedge |
|||
Petrochemical marketing: |
|||||
Forecasted purchases of petrochemical products (MMBbls) |
n/a |
Cash flow hedge |
|||
Forecasted sales of petrochemical products (MMBbls) |
n/a |
Cash flow hedge |
|||
Derivatives not designated as hedging instruments: |
|||||
Natural gas risk management activities (Bcf) (3) |
Mark-to-market |
||||
NGL risk management activities (MMBbls) (3) |
Mark-to-market |
||||
Refined products risk management activities (MMBbls) (3) |
n/a |
Mark-to-market |
|||
Crude oil risk management activities (MMBbls) (3) |
Mark-to-market |
(1) |
|
(2) |
|
(3) |
Asset Derivatives |
Liability Derivatives |
||||||||||||||
December 31, 2020 |
December 31, 2019 |
December 31, 2020 |
December 31, 2019 |
||||||||||||
Balance Sheet Location |
Fair Value |
Balance Sheet Location |
Fair Value |
Balance Sheet Location |
Fair Value |
Balance Sheet Location |
Fair Value |
||||||||
Derivatives designated as hedging instruments |
|||||||||||||||
Interest rate derivatives |
Current assets |
$ |
Current assets |
$ |
Current liabilities |
$ |
Current liabilities |
$ |
|||||||
Interest rate derivatives |
Other assets |
Other assets |
Other liabilities |
Other liabilities |
|||||||||||
Total interest rate derivatives |
|||||||||||||||
Commodity derivatives |
Current assets |
Current assets |
Current liabilities |
Current liabilities |
|||||||||||
Commodity derivatives |
Other assets |
Other assets |
Other liabilities |
Other liabilities |
|||||||||||
Total commodity derivatives |
|||||||||||||||
Total derivatives designated as hedging instruments |
$ |
$ |
$ |
$ |
|||||||||||
Derivatives not designated as hedging instruments |
|||||||||||||||
Commodity derivatives |
Current assets |
Current assets |
Current liabilities |
Current liabilities |
|||||||||||
Commodity derivatives |
Other assets |
Other assets |
Other liabilities |
Other liabilities |
|||||||||||
Total commodity derivatives |
|||||||||||||||
Total derivatives not designated as hedging instruments |
$ |
$ |
$ |
$ |
Offsetting of Financial Assets and Derivative Assets |
||||||||||||||||||||||||||||
Gross Amounts Not Offset in the Balance Sheet |
||||||||||||||||||||||||||||
Gross Amounts of Recognized Assets |
Gross Amounts Offset in the Balance Sheet |
Amounts of Assets Presented in the Balance Sheet |
Financial Instruments |
Cash Collateral Paid |
Cash Collateral Received |
Amounts That Would Have Been Presented On Net Basis |
||||||||||||||||||||||
(i) |
(ii) |
(iii) = (i) – (ii) |
(iv) |
(v) = (iii) + (iv) |
||||||||||||||||||||||||
As of December 31, 2020: |
||||||||||||||||||||||||||||
Interest rate derivatives |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Commodity derivatives |
( |
) |
||||||||||||||||||||||||||
As of December 31, 2019: |
||||||||||||||||||||||||||||
Commodity derivatives |
$ |
$ |
$ |
( |
) |
$ |
( |
) |
$ |
$ |
Offsetting of Financial Liabilities and Derivative Liabilities |
||||||||||||||||||||||||
Gross Amounts Not Offset in the Balance Sheet |
||||||||||||||||||||||||
Gross Amounts of Recognized Liabilities |
Gross Amounts Offset in the Balance Sheet |
Amounts of Liabilities Presented in the Balance Sheet |
Financial Instruments |
Cash Collateral Paid |
Amounts That Would Have Been Presented On Net Basis |
|||||||||||||||||||
(i) |
(ii) |
(iii) = (i) – (ii) |
(iv) |
(v) = (iii) + (iv) |
||||||||||||||||||||
As of December 31, 2020: |
||||||||||||||||||||||||
Interest rate derivatives |
$ |
$ |
$ |
$ |
$ |
$ |
||||||||||||||||||
Commodity derivatives |
( |
) |
( |
) |
||||||||||||||||||||
As of December 31, 2019: |
||||||||||||||||||||||||
Interest rate derivatives |
$ |
$ |
$ |
$ |
$ |
$ |
||||||||||||||||||
Commodity derivatives |
( |
) |
Derivatives in Fair Value Hedging Relationships |
Location |
Gain (Loss) Recognized in Income on Derivative |
|||||||||||
For the Year Ended December 31, |
|||||||||||||
2020 |
2019 |
2018 |
|||||||||||
Interest rate derivatives |
Interest expense |
$ |
$ |
$ |
|||||||||
Commodity derivatives |
Revenue |
( |
) |
||||||||||
Total |
$ |
( |
) |
$ |
$ |
Derivatives in Fair Value Hedging Relationships |
Location |
Gain (Loss) Recognized in Income on Hedged Item |
|||||||||||
For the Year Ended December 31, |
|||||||||||||
2020 |
2019 |
2018 |
|||||||||||
Interest rate derivatives |
Interest expense |
$ |
$ |
$ |
( |
) |
|||||||
Commodity derivatives |
Revenue |
( |
) |
||||||||||
Total |
$ |
$ |
$ |
( |
) |
Derivatives in Cash Flow Hedging Relationships |
Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative |
|||||||||||
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Interest rate derivatives |
$ |
( |
) |
$ |
$ |
|||||||
Commodity derivatives – Revenue (1) |
||||||||||||
Commodity derivatives – Operating costs and expenses (1) |
( |
) |
( |
) |
||||||||
Total |
$ |
( |
) |
$ |
$ |
(1) |
Derivatives in Cash Flow Hedging Relationships |
Location |
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income |
|||||||||||
For the Year Ended December 31, |
|||||||||||||
2020 |
2019 |
2018 |
|||||||||||
Interest rate derivatives |
Interest expense |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
|||
Commodity derivatives |
Revenue |
||||||||||||
Commodity derivatives |
Operating costs and expenses |
( |
) |
( |
) |
( |
) |
||||||
Total |
$ |
$ |
$ |
Derivatives Not Designated as Hedging Instruments |
Location |
Gain (Loss) Recognized in Income on Derivative |
|||||||||||
For the Year Ended December 31, |
|||||||||||||
2020 |
2019 |
2018 |
|||||||||||
Interest rate derivatives |
Interest expense |
$ |
$ |
( |
) |
$ |
|||||||
Commodity derivatives |
Revenue |
( |
) |
||||||||||
Commodity derivatives |
Operating costs and expenses |
( |
) |
( |
) |
||||||||
Total |
$ |
$ |
( |
) |
$ |
( |
) |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Mark-to-market gains (losses) in gross operating margin: |
||||||||||||
NGL Pipelines & Services |
$ |
$ |
( |
) |
$ |
|||||||
Crude Oil Pipelines & Services |
( |
) |
||||||||||
Natural Gas Pipelines & Services |
( |
) |
||||||||||
Petrochemical & Refined Products Services |
( |
) |
||||||||||
Total mark-to-market impact on gross operating margin |
( |
) |
||||||||||
Mark-to-market gains (losses) in interest expense |
( |
) |
( |
) |
||||||||
Total |
$ |
$ |
( |
) |
$ |
( |
) |
At December 31, 2020 Fair Value Measurements Using |
||||||||||||||||
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Total |
|||||||||||||
Financial assets: |
||||||||||||||||
Interest rate derivatives |
$ |
$ |
$ |
$ |
||||||||||||
Commodity derivatives: |
||||||||||||||||
Value before application of CME Rule 814 |
||||||||||||||||
Impact of CME Rule 814 change |
( |
) |
( |
) |
( |
) |
( |
) |
||||||||
Total commodity derivatives |
||||||||||||||||
Total |
$ |
$ |
$ |
$ |
||||||||||||
Financial liabilities: |
||||||||||||||||
Interest rate derivatives |
$ |
$ |
$ |
$ |
||||||||||||
Commodity derivatives: |
||||||||||||||||
Value before application of CME Rule 814 |
||||||||||||||||
Impact of CME Rule 814 change |
( |
) |
( |
) |
( |
) |
( |
) |
||||||||
Total commodity derivatives |
||||||||||||||||
Total |
$ |
$ |
$ |
$ |
At December 31, 2019 Fair Value Measurements Using |
||||||||||||||||
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Total |
|||||||||||||
Financial assets: |
||||||||||||||||
Commodity derivatives: |
||||||||||||||||
Value before application of CME Rule 814 |
$ |
$ |
$ |
$ |
||||||||||||
Impact of CME Rule 814 change |
( |
) |
( |
) |
( |
) |
||||||||||
Total commodity derivatives |
||||||||||||||||
Total |
$ |
$ |
$ |
$ |
||||||||||||
Financial liabilities: |
||||||||||||||||
Liquidity Option (see Note 17) |
$ |
$ |
$ |
$ |
||||||||||||
Interest rate derivatives |
||||||||||||||||
Commodity derivatives: |
||||||||||||||||
Value before application of CME Rule 814 |
||||||||||||||||
Impact of CME Rule 814 change |
( |
) |
( |
) |
( |
) |
||||||||||
Total commodity derivatives |
||||||||||||||||
Total |
$ |
$ |
$ |
$ |
test |
For the Year Ended December 31, |
||||||||
test |
Location |
2020 |
2019 |
||||||
Financial liability balance, net, January 1 |
$ |
( |
) |
$ |
( |
) |
|||
Total gains (losses) included in: |
|||||||||
Net income (1) |
Revenue |
( |
) |
||||||
Net income |
Other expense, net – Liquidity Option |
( |
) |
( |
) |
||||
Other comprehensive income (loss) |
Commodity derivative instruments – changes in fair value of cash flow hedges |
( |
) |
( |
) |
||||
Settlements (1) |
Revenue |
( |
) |
||||||
Transfer out of Level 3 – Liquidity Option (2) |
|||||||||
Other transfers out of Level 3 |
|||||||||
Financial liability balance, net, December 31 |
$ |
( |
) |
$ |
( |
) |
(1) |
|
(2) |
Components of Carrying Value at December 31, 2020 by Level of Fair Value Measurement |
||||||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Carrying Values at December 31, 2020 |
Impairment Charges Recognized in 2020 |
||||||||||||||||
Long-lived assets held and used: (1) |
||||||||||||||||||||
Marine transportation business |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||
South Texas natural gas gathering and processing |
(1) |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Revenues – related parties: |
||||||||||||
Unconsolidated affiliates |
$ |
$ |
$ |
|||||||||
Costs and expenses – related parties: |
||||||||||||
EPCO and its privately held affiliates |
$ |
$ |
$ |
|||||||||
Unconsolidated affiliates |
||||||||||||
Total |
$ |
$ |
$ |
December 31, |
||||||||
2020 |
2019 |
|||||||
Accounts receivable - related parties: |
||||||||
EPCO and its privately held affiliates |
$ |
$ |
||||||
Unconsolidated affiliates |
||||||||
Total |
$ |
$ |
||||||
Accounts payable - related parties: |
||||||||
EPCO and its privately held affiliates |
$ |
$ |
||||||
Unconsolidated affiliates |
||||||||
Total |
$ |
$ |
Total Number of Limited Partner Interests Held |
Percentage of Limited Partner Interests Outstanding |
|||
% |
||||
% |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Operating costs and expenses |
$ |
$ |
$ |
|||||||||
General and administrative expenses |
||||||||||||
Total costs and expenses |
$ |
$ |
$ |
• | For the years ended December 31, 2020, 2019 and 2018, we paid Seaway $ |
• | For the years ended December 31, 2020, 2019 and 2018, we purchased $ |
• | We pay Promix for the transportation, storage and fractionation of NGLs. Expenses with Promix were $ |
• | For the years ended December 31, 2020, 2019 and 2018, we paid Texas Express $ |
• | For the years ended December 31, 2020, 2019 and 2018, we paid Eagle Ford Crude Oil Pipeline $ |
• | We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Deferred tax benefit attributable to OTA |
$ |
$ |
$ |
|||||||||
Texas Margin Tax |
( |
) |
( |
) |
( |
) |
||||||
Other |
( |
) |
( |
) |
||||||||
Benefit from (provision for) income taxes |
$ |
$ |
( |
) |
$ |
( |
) |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Current portion of income tax benefit (provision): |
||||||||||||
Federal |
$ |
$ |
$ |
( |
) |
|||||||
State |
( |
) |
( |
) |
( |
) |
||||||
Foreign |
( |
) |
( |
) |
( |
) |
||||||
Total current portion |
( |
) |
( |
) |
( |
) |
||||||
Deferred portion of income tax benefit (provision): |
||||||||||||
Federal |
( |
) |
||||||||||
State |
( |
) |
( |
) |
||||||||
Foreign |
||||||||||||
Total deferred portion |
( |
) |
( |
) |
||||||||
Total benefit from (provision for) income taxes |
$ |
$ |
( |
) |
$ |
( |
) |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Pre-Tax Net Book Income (“NBI”) |
$ |
$ |
$ |
|||||||||
Texas Margin Tax (1) |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
|||
State income tax benefit (provision), net of federal benefit (2) |
( |
) |
( |
) |
||||||||
Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities |
( |
) |
( |
) |
||||||||
Federal benefit attributable to settlement of Liquidity Option (2) |
||||||||||||
Other differences |
( |
) |
( |
) |
||||||||
Benefit from (provision for) income taxes |
$ |
$ |
( |
) |
$ |
( |
) |
|||||
Effective income tax rate |
% |
( |
)% |
( |
)% |
(1) |
|
(2) |
December 31, |
||||||||
2020 |
2019 |
|||||||
Deferred tax liabilities: |
||||||||
Attributable to investment in OTA |
$ |
$ |
||||||
Attributable to property, plant and equipment |
||||||||
Attributable to investments in other entities |
||||||||
Total deferred tax liabilities |
||||||||
Less deferred tax assets: |
||||||||
Net operating loss carryovers (1) |
||||||||
Temporary differences related to Texas Margin Tax |
||||||||
Total deferred tax assets |
||||||||
Total net deferred tax liabilities |
$ |
$ |
(1) |
Payment or Settlement due by Period |
||||||||||||||||||||||||||||
Contractual Obligations |
Total |
2021 |
2022 |
2023 |
2024 |
2025 |
Thereafter |
|||||||||||||||||||||
Scheduled maturities of debt obligations |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Estimated cash interest payments |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Operating lease obligations |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Purchase obligations: |
||||||||||||||||||||||||||||
Product purchase commitments: |
||||||||||||||||||||||||||||
Estimated payment obligations: |
||||||||||||||||||||||||||||
Natural gas |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
NGLs |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Crude oil |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Petrochemicals and refined products |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Other |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
|||||||||||||||||||||
Service payment commitments |
$ |
$ |
$ |
$ |
$ |
$ |
$ |
Asset Category |
ROU Asset Carrying Value (1) |
Lease Liability Carrying Value (2) |
Weighted- Average Remaining Term |
Weighted- Average Discount Rate (3) |
|||||||||
Storage and pipeline facilities |
$ |
$ |
% |
||||||||||
Transportation equipment |
% |
||||||||||||
Office and warehouse space |
% |
||||||||||||
Total |
$ |
$ |
(1) |
|
(2) |
|
(3) |
For the Year Ended December, |
||||||||
2020 |
2019 |
|||||||
Long-term operating leases: |
||||||||
Fixed lease expense: |
||||||||
Non-cash lease expense (amortization of ROU assets) |
$ |
$ |
||||||
Related accretion expense on lease liability balances |
||||||||
Total fixed lease expense |
||||||||
Variable lease expense |
||||||||
Subtotal operating lease expense |
||||||||
Short-term operating leases |
||||||||
Total operating lease expense |
$ |
$ |
• | 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, 2020 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. |
• | 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. |
December 31, |
||||||||
2020 |
2019 |
|||||||
Noncurrent portion of AROs (see Note 4) |
$ |
$ |
||||||
Deferred revenues – non-current portion (see Note 9) |
||||||||
Liquidity Option liability |
||||||||
Lease liability – non-current portion |
||||||||
Derivative liabilities |
||||||||
Other |
||||||||
Total |
$ |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Decrease (increase) in: |
||||||||||||
Accounts receivable – trade |
$ |
$ |
( |
) |
$ |
|||||||
Accounts receivable – related parties |
( |
) |
( |
) |
||||||||
Inventories |
( |
) |
( |
) |
||||||||
Prepaid and other current assets |
( |
) |
||||||||||
Other assets |
( |
) |
( |
) |
( |
) |
||||||
Increase (decrease) in: |
||||||||||||
Accounts payable – trade |
( |
) |
||||||||||
Accounts payable – related parties |
( |
) |
||||||||||
Accrued product payables |
( |
) |
||||||||||
Accrued interest |
||||||||||||
Other current liabilities |
( |
) |
( |
) |
||||||||
Other liabilities |
( |
) |
( |
) |
||||||||
Net effect of changes in operating accounts |
$ |
( |
) |
$ |
( |
) |
$ |
|||||
Cash payments for interest, net of $ capitalized in 2020, 2019 and 2018, respectively |
$ |
$ |
$ |
|||||||||
Cash payments for federal and state income taxes |
$ |
$ |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Sale of crude oil pipeline system |
$ |
$ |
$ |
|||||||||
Other asset sales |
||||||||||||
Total |
$ |
$ |
$ |
For the Year Ended December 31, |
||||||||||||
2020 |
2019 |
2018 |
||||||||||
Gain on sale of crude oil pipeline system |
$ |
$ |
$ |
|||||||||
Net gains attributable to other asset sales |
||||||||||||
Total |
$ |
$ |
$ |
SCHEDULED VESTING DATES
|
CUMULATIVE VESTED PERCENTAGE
|
[ ], 20___
|
25%
|
[ ], 20___
|
50%
|
[ ], 20___
|
75%
|
[ ], 20___
|
100%
|
COMPANY
|
EMPLOYEE
|
Enterprise Products Company
|
|
By: /s/ Randa L. Duncan
|
/s/ Christian M. Nelly
|
Name: Randa L. Duncan
|
Name: Christian M. Nelly
|
Title: Chairman
|
Dated: /s/ April 4, 2019
|
Dated: /s/ 4/10, 2019
|
Name of Subsidiary
|
Jurisdiction
of Formation
|
Effective Ownership
|
38 Niente LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Acadian Gas Pipeline System
|
Delaware
|
TXO-Acadian Gas Pipeline, LLC – 50%
MCN Acadian Gas Pipeline, LLC – 50%
|
Acadian Gas, LLC
|
Delaware
|
Duncan Energy Partners L.P. – 100%
|
Adamana Land Company, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Arizona Gas Storage, L.L.C.
|
Delaware
|
Enterprise Arizona Gas, L.L.C. – 60%
Third Party – 40%
|
Baton Rouge Fractionators LLC
|
Delaware
|
Enterprise Products Operating LLC – 32.25%
Third Parties – 67.75%
|
Baton Rouge Pipeline LLC
|
Delaware
|
Baton Rouge Fractionators LLC – 100%
|
Baton Rouge Propylene Concentrator LLC
|
Delaware
|
Enterprise Products Operating LLC – 30%
Third Parties – 70%
|
Baymark Pipeline LLC
|
Texas
|
Enterprise Products Operating LLC – 70%
Third Party - 30%
|
Belle Rose NGL Pipeline, L.L.C.
|
Delaware
|
Enterprise NGL Pipelines, LLC –41.67%
Enterprise Products Operating LLC – 58.33%
|
Belvieu Environmental Fuels GP, LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Belvieu Environmental Fuels LLC
|
Texas
|
Enterprise Products Operating LLC – 99%
Belvieu Environmental Fuels GP, LLC – 1%
|
Breviloba, LLC
|
Texas
|
Enterprise Products Operating LLC – 67%
Third Party – 33%
|
BTA ETG Gathering LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
BTA Gas Processing LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Cajun Pipeline Company, LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Calcasieu Gas Gathering System
|
Texas
|
TXO-Acadian Gas Pipeline, LLC – 50%
MCN Acadian Gas Pipeline, LLC – 50%
|
Canadian Enterprise Gas Products, Ltd.
|
Alberta, Canada
|
Enterprise Products Operating LLC – 100%
|
Centennial Pipeline LLC
|
Delaware
|
Enterprise TE Products Pipeline Company, LLC – 50%
Third Party – 50%
|
Chama Gas Services, LLC
|
Delaware
|
Enterprise New Mexico Ventures, LLC – 75%
Third Party – 25%
|
Channelview Fleeting Services, L.L.C.
|
Texas
|
Enterprise Marine Services LLC – 100%
|
Chaparral Pipeline Company, LLC
|
Texas
|
Enterprise Midstream Companies LLC – 99.999%
Enterprise NGL Pipelines II LLC – 0.001%
|
Chunchula Pipeline Company, LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
CTCO of Texas, LLC
|
Texas
|
Enterprise Marine Services LLC – 100%
|
Cypress Gas Marketing, LLC
|
Delaware
|
Acadian Gas, LLC – 100%
|
Dean Pipeline Company, LLC
|
Texas
|
Enterprise Midstream Companies LLC – 99.999%
Enterprise NGL Pipelines II LLC – 0.001%
|
Delaware Basin Gas Processing LLC
|
Delaware
|
Enterprise GC LLC – 100%
|
DEP Holdings, LLC
|
Delaware
|
Enterprise GTM Holdings L.P. – 100%
|
DEP Offshore Port System, LLC
|
Texas
|
Duncan Energy Partners L.P. – 100%
|
Dixie Pipeline Company LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Name of Subsidiary
|
Jurisdiction
of Formation
|
Effective Ownership
|
Duncan Energy Partners L.P.
|
Delaware
|
Enterprise GTM Holdings L.P. – 99.3%
DEP Holdings, LLC – 0.700%
|
Eagle Ford Pipeline LLC
|
Delaware
|
Enterprise Products Operating LLC – 50%
Third Party – 50%
|
Eagle Ford Terminals Corpus Christi LLC
|
Delaware
|
Enterprise Products Operating LLC – 50%
Third Party – 50%
|
EFS Midstream LLC
|
Delaware
|
Enterprise Acquisition Holdings LLC – 100%
|
EF Terminals Corpus Christi LLC
|
Delaware
|
Eagle Ford Terminals Corpus Christi LLC – 100%
|
Electra Shipyard Services LLC
|
Texas
|
Enterprise Marine Services LLC – 100%
|
Electric E Power Marketing LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Energy Ventures, LLC
|
Colorado
|
Enterprise Crude Oil LLC – 100%
|
Enterprise Acquisition Holdings LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise Appelt, LLC
|
Texas
|
Enterprise Houston Ship Channel, L.P. – 100%
|
Enterprise Arizona Gas, LLC
|
Delaware
|
Enterprise Field Services, LLC – 100%
|
Enterprise Blue Ivy LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Enterprise Crude GP LLC
|
Delaware
|
TCTM, L.P. – 100%
|
Enterprise Crude Oil LLC
|
Texas
|
TCTM, L.P. – 99.99%
Enterprise Crude GP LLC – 0.01%
|
Enterprise Crude Pipeline LLC
|
Texas
|
TCTM, L.P. – 99.99%
Enterprise Crude GP LLC – 0.01%
|
Enterprise Crude Terminals and Storage LLC
|
Texas
|
Enterprise Crude GP LLC – 100%
|
Enterprise Custom Marketing LLC
|
Delaware
|
Enterprise Crude Oil LLC – 100%
|
Enterprise EF78 LLC
|
Delaware
|
Enterprise Products Texas Operating LLC – 75%
Third Party – 25%
|
Enterprise Field Services, LLC
|
Texas
|
Enterprise GTM Holdings L.P. – 100%
|
Enterprise Field Services (Offshore) LLC
|
Texas
|
Enterprise GTM Holdings L.P. – 100%
|
Enterprise Fractionation, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise Gas Liquids LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Enterprise Gas Processing, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise Gathering II LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise Gathering LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise GC LLC
|
Texas
|
Duncan Energy Partners L.P. – 100%
|
Enterprise GP LLC
|
Delaware
|
Enterprise TE Partners L.P. – 100%
|
Enterprise GTM Holdings L.P.
|
Delaware
|
Enterprise Products Operating LLC – 99%
Enterprise GTMGP, LLC – 1%
|
Enterprise GTMGP, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise Houston Ship Channel GP, LLC
|
Texas
|
Enterprise Terminaling Services, L.P. – 100%
|
Enterprise Houston Ship Channel, L.P.
|
Texas
|
Enterprise Terminaling Services, L.P. – 99%
Enterprise Houston Ship Channel GP, LLC – 1%
|
Enterprise Hydrocarbons L.P.
|
Delaware
|
Enterprise Products Texas Operating LLC – 99%
Enterprise Products Operating LLC – 1%
|
Enterprise Interstate Crude LLC
|
Texas
|
Enterprise Crude GP LLC – 100%
|
Enterprise Intrastate LLC
|
Delaware
|
Duncan Energy Partners L.P. – 100%
|
Enterprise Jonah Gas Gathering Company LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Name of Subsidiary
|
Jurisdiction
of Formation
|
Effective Ownership
|
Enterprise Logistic Services LLC
(DBA Enterprise Transportation Company)
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Enterprise Lou-Tex NGL Pipeline L.P.
|
Texas
|
Enterprise Products Operating LLC – 99%
HSC Pipeline Partnership, LLC – 1%
|
Enterprise Lou-Tex Propylene Pipeline LLC
|
Texas
|
Duncan Energy Partners L.P. – 100%
|
Enterprise Louisiana Pipeline LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Enterprise Marine Services LLC
|
Delaware
|
Enterprise TE Partners L.P. – 100%
|
Enterprise Midstream Companies LLC
|
Texas
|
Enterprise TE Partners L.P. – 99.999%
Enterprise GP LLC – 0.001%
|
Enterprise Mont Belvieu Program Company
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Enterprise Natural Gas Pipeline LLC
|
Delaware
|
Enterprise GTM Holdings L.P. – 100%
|
Enterprise Navigator Ethylene Terminal LLC
|
Texas
|
Enterprise Products Operating LLC – 50%
Third Party – 50%
|
Enterprise New Mexico Ventures, LLC
|
Delaware
|
Enterprise Field Services, LLC – 100%
|
Enterprise NGL Pipelines II LLC
|
Delaware
|
Enterprise Midstream Companies LLC – 100%
|
Enterprise NGL Pipelines, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise NGL Private Lines & Storage, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise Offshore Port System, LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Enterprise Pathfinder, LLC
|
Delaware
|
Enterprise GTM Holdings L.P. – 100%
|
Enterprise Pelican Pipeline L.P.
|
Texas
|
Evangeline Gulf Coast Gas, LLC – 90%
Evangeline Gas Corp. – 10%
|
Enterprise Plevna Marketing LLC
|
Delaware
|
Enterprise Crude Oil LLC – 100%
|
Enterprise Products BBCT LLC
|
Texas
|
Enterprise Crude Oil LLC – 99.99%
Enterprise Crude GP LLC – 0.01%
|
Enterprise Products Marketing Company LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Enterprise Products OLPGP, Inc.
|
Delaware
|
Enterprise Products Partners L.P. – 100%
|
Enterprise Products Operating LLC
|
Texas
|
Enterprise Products Partners L.P. – 99.999%
Enterprise Products OLPGP, Inc. – 0.001%
|
Enterprise Products Pipeline Company LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise Products Texas Operating LLC
|
Texas
|
Enterprise Products Operating LLC – 99%
Enterprise Products OLPGP, Inc. – 1%
|
Enterprise Propane Terminals and Storage, LLC
|
Delaware
|
Enterprise Terminals & Storage, LLC – 100%
|
Enterprise Refined Products Company LLC
|
Delaware
|
Enterprise Products Operating LLC –100%
|
Enterprise Refined Products Marketing
Company LLC
|
Delaware
|
Enterprise Refined Products Company LLC – 100%
|
Enterprise Sage Marketing LLC
|
Delaware
|
Enterprise Crude Oil LLC – 100%
|
Enterprise Seaway L.P.
|
Delaware
|
Enterprise Products Operating LLC – 99.99%
Enterprise Crude GP LLC – 0.01%
|
Enterprise TE Investments LLC
|
Delaware
|
Enterprise Products Pipeline Company LLC – 100%
|
Enterprise TE Partners L.P.
|
Delaware
|
Enterprise Products Pipeline Company LLC – 2%
Enterprise Products Operating LLC – 98%
|
Enterprise TE Products Pipeline Company LLC
|
Texas
|
Enterprise TE Partners L.P. – 99.999%
Enterprise GP LLC – 0.001%
|
Enterprise Terminaling Services GP, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Enterprise Terminaling Services, L.P.
|
Delaware
|
Enterprise Products Operating LLC – 98%
Enterprise Terminaling Services GP, LLC – 2%
|
Enterprise Terminalling LLC
|
Texas
|
Enterprise Products Operating LLC – 99%
Enterprise Gas Liquids LLC – 1%
|
Enterprise Terminals & Storage, LLC
|
Delaware
|
Mapletree, LLC – 100%
|
Enterprise Texas Pipeline LLC
|
Texas
|
Duncan Energy Partners L.P. – 100%
|
Name of Subsidiary
|
Jurisdiction
of Formation
|
Effective Ownership
|
Enterprise White River Hub, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Evangeline Gas Corp.
|
Delaware
|
Evangeline Gulf Coast Gas, LLC – 100%
|
Evangeline Gulf Coast Gas, LLC
|
Delaware
|
Acadian Gas, LLC – 100%
|
Front Range Pipeline LLC
|
Delaware
|
Enterprise Products Operating LLC – 33.33%
Third Parties – 66.67%
|
Groves RGP Pipeline LLC
|
Texas
|
Enterprise Products Operating LLC – 99%
Enterprise Products Texas Operating LLC – 1%
|
HSC Pipeline Partnership, LLC
|
Texas
|
Enterprise Products Operating LLC – 99%
Enterprise Products OLPGP, Inc. – 1%
|
JMRS Transport Services, Inc.
|
Delaware
|
Enterprise Logistic Services LLC – 100%
|
K/D/S Promix, L.L.C.
|
Delaware
|
Enterprise Fractionation, LLC – 50%
Third Parties – 50%
|
La Porte Pipeline Company, L.P.
|
Texas
|
Enterprise Products Operating LLC – 79.24%
La Porte Pipeline GP, LLC – 1.0%
Third Party – 19.76%
|
La Porte Pipeline GP, L.L.C.
|
Delaware
|
Enterprise Products Operating LLC – 80.04%
Third Party – 19.96%
|
Leveret Pipeline Company LLC
|
Texas
|
Enterprise Field Services, LLC – 100%
|
M2E3 LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
M2E4 LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Mapletree, LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
MCN Acadian Gas Pipeline, LLC
|
Delaware
|
Acadian Gas, LLC – 100%
|
MCN Pelican Interstate Gas, LLC
|
Delaware
|
Acadian Gas, LLC – 100%
|
Mid-America Pipeline Company, LLC
|
Texas
|
Mapletree, LLC – 100%
|
Mont Belvieu Caverns, LLC
|
Delaware
|
Duncan Energy Partners L.P. – 100%
|
Neches Pipeline System
|
Delaware
|
TXO-Acadian Gas Pipeline, LLC – 50%
MCN Acadian Gas Pipeline, LLC – 50%
|
Norco-Taft Pipeline, LLC
|
Delaware
|
Enterprise NGL Private Lines & Storage, LLC – 100%
|
Old Ocean Pipeline, LLC
|
Texas
|
Enterprise Products Operating – 50%
Third Party – 50%
|
Olefins Terminal LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
OTA Holdings, Inc.
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Panola Pipeline Company, LLC
|
Texas
|
Enterprise Midstream Companies LLC – 55%
Third Parties – 45%
|
Pascagoula Gas Processing LLC
|
Texas
|
Enterprise Gas Processing, LLC – 75%
Third Party – 25%
|
Pontchartrain Natural Gas System
|
Texas
|
TXO-Acadian Gas Pipeline, LLC – 50%
MCN Acadian Gas Pipeline, LLC – 50%
|
Port Neches GP LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Port Neches Pipeline LLC
|
Texas
|
Enterprise Products Operating LLC – 99%
Port Neches GP LLC – 1%
|
QP-LS, LLC
|
Wyoming
|
Enterprise Products BBCT LLC – 100%
|
Quanah Pipeline Company, LLC
|
Texas
|
Enterprise Midstream Companies LLC – 99.999%
Enterprise NGL Pipelines II LLC – 0.001%
|
Rio Grande Pipeline Company LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Sabine Propylene Pipeline LLC
|
Texas
|
Duncan Energy Partners L.P. – 100%
|
Seaway Crude Holdings LLC
|
Delaware
|
Enterprise Seaway L.P. – 50%
Third Party – 50%
|
Seaway Crude Pipeline Company LLC
|
Delaware
|
Seaway Crude Holdings LLC – 100%
|
Seaway Intrastate LLC
|
Delaware
|
Seaway Crude Holdings LLC – 100%
|
Seaway Marine LLC
|
Delaware
|
Seaway Intrastate LLC – 100%
|
Name of Subsidiary
|
Jurisdiction
of Formation
|
Effective Ownership
|
Seminole Pipeline Company LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Skelly-Belvieu Pipeline Company, L.L.C.
|
Delaware
|
Enterprise Products Operating LLC – 50%
Third Party – 50%
|
Sorrento Pipeline Company, LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
South Texas NGL Pipelines, LLC
|
Delaware
|
Duncan Energy Partners L.P. – 100%
|
SPOT Terminal Operating LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
SPOT Terminal Services LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
Tarpon Land Holdings LLC
|
Texas
|
Enterprise Products Operating LLC – 100%
|
TCTM, L.P.
|
Delaware
|
Enterprise TE Partners L.P. – 99.999%
Enterprise GP LLC – 0.001%
|
TECO Gas Gathering LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
TECO Gas Processing LLC
|
Delaware
|
Enterprise Products Operating LLC – 100%
|
Tejas-Magnolia Energy, LLC
|
Delaware
|
Pontchartrain Natural Gas System – 96.6%
MCN Pelican Interstate Gas, LLC – 3.4%
|
TEPPCO O/S Port System, LLC
|
Texas
|
Enterprise Crude GP LLC – 100%
|
Texas Express Gathering LLC
|
Delaware
|
Enterprise Products Operating LLC – 45%
Third Parties – 55%
|
Texas Express Pipeline LLC
|
Delaware
|
Enterprise Products Operating LLC – 35%
Third Parties – 65%
|
Transport 4, L.L.C.
|
Delaware
|
Enterprise TE Products Pipeline Company LLC – 25%
Third Parties – 75%
|
Tri-States NGL Pipeline, L.L.C.
|
Delaware
|
Enterprise Products Operating LLC – 50%
Enterprise NGL Pipelines, LLC – 33.3%
Third Party – 16.67%
|
TXO-Acadian Gas Pipeline, LLC
|
Delaware
|
Acadian Gas, LLC – 100%
|
Venice Energy Services Company, L.L.C.
|
Delaware
|
Enterprise Gas Processing LLC – 13.1%
Third Parties – 86.9%
|
White River Hub, LLC
|
Delaware
|
Enterprise White River Hub, LLC – 50%
Third Party – 50%
|
Whitethorn Pipeline Company LLC
|
Texas
|
Enterprise Products Operating LLC – 80%
Third Party – 20%
|
Wilcox Pipeline Company, LLC
|
Texas
|
Enterprise Midstream Companies LLC – 99.999%
Enterprise NGL Pipelines II LLC – 0.001%
|
Wilprise Pipeline Company, L.L.C.
|
Delaware
|
Enterprise Products Operating LLC – 74.7%
Third Party – 25.3%
|
Amounts Outstanding at
|
||||
Guaranteed Securities
|
December 31, 2020
|
|||
Senior Notes TT, 2.80% fixed-rate, due February 2021
|
$
|
750.0
|
||
Senior Notes RR, 2.85% fixed-rate, due April 2021
|
575.0
|
|||
Senior Notes VV, 3.50% fixed-rate, due February 2022
|
750.0
|
|||
Senior Notes CC, 4.05% fixed-rate, due February 2022
|
650.0
|
|||
Senior Notes HH, 3.35% fixed-rate, due March 2023
|
1,250.0
|
|||
Senior Notes JJ, 3.90% fixed-rate, due February 2024
|
850.0
|
|||
Senior Notes MM, 3.75% fixed-rate, due February 2025
|
1,150.0
|
|||
Senior Notes PP, 3.70% fixed-rate, due February 2026
|
875.0
|
|||
Senior Notes SS, 3.95% fixed-rate, due February 2027
|
575.0
|
|||
Senior Notes WW, 4.15% fixed-rate, due October 2028
|
1,000.0
|
|||
Senior Notes YY, 3.125% fixed-rate, due July 2029
|
1,250.0
|
|||
Senior Notes AAA, 2.80% fixed-rate, due January 2030
|
1,250.0
|
|||
Senior Notes D, 6.875% fixed-rate, due March 2033
|
500.0
|
|||
Senior Notes H, 6.65% fixed-rate, due October 2034
|
350.0
|
|||
Senior Notes J, 5.75% fixed-rate, due March 2035
|
250.0
|
|||
Senior Notes W, 7.55% fixed-rate, due April 2038
|
399.6
|
|||
Senior Notes R, 6.125% fixed-rate, due October 2039
|
600.0
|
|||
Senior Notes Z, 6.45% fixed-rate, due September 2040
|
600.0
|
|||
Senior Notes BB, 5.95% fixed-rate, due February 2041
|
750.0
|
|||
Senior Notes DD, 5.70% fixed-rate, due February 2042
|
600.0
|
|||
Senior Notes EE, 4.85% fixed-rate, due August 2042
|
750.0
|
|||
Senior Notes GG, 4.45% fixed-rate, due February 2043
|
1,100.0
|
|||
Senior Notes II, 4.85% fixed-rate, due March 2044
|
1,400.0
|
|||
Senior Notes KK, 5.10% fixed-rate, due February 2045
|
1,150.0
|
|||
Senior Notes QQ, 4.90% fixed-rate, due May 2046
|
975.0
|
|||
Senior Notes UU, 4.25% fixed-rate, due February 2048
|
1,250.0
|
|||
Senior Notes XX, 4.80% fixed-rate, due February 2049
|
1,250.0
|
|||
Senior Notes ZZ, 4.20% fixed-rate, due January 2050
|
1,250.0
|
|||
Senior Notes BBB, 3.70% fixed-rate, due January 2051
|
1,000.0
|
|||
Senior Notes DDD, 3.20% fixed-rate, due February 2052
|
1,000.0
|
|||
Senior Notes NN, 4.95% fixed-rate, due October 2054
|
400.0
|
|||
Senior Notes CCC, 3.95% fixed rate, due January 2060
|
1,000.0
|
|||
Junior Subordinated Notes C, variable-rate, due June 2067
|
232.2
|
|||
Junior Subordinated Notes D, fixed/variable-rate, due August 2077
|
700.0
|
|||
Junior Subordinated Notes E, fixed/variable-rate, due August 2077
|
1,000.0
|
|||
Junior Subordinated Notes F, fixed/variable-rate, due February 2078
|
700.0
|
1.
|
I have reviewed this annual report on Form 10-K of Enterprise Products Partners L.P;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
|
/s/ A. James Teague
|
||
Name:
|
A. James Teague
|
|
Title:
|
Co-Chief Executive Officer of Enterprise Products Holdings LLC, the General Partner of Enterprise Products Partners L.P.
|
1.
|
I have reviewed this annual report on Form 10-K of Enterprise Products Partners L.P.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
|
/s/ W. Randall Fowler
|
||
Name:
|
W. Randall Fowler
|
|
Title:
|
Co-Chief Executive Officer and Chief Financial Officer of Enterprise Products Holdings LLC, the General Partner of Enterprise Products Partners L.P.
|
(1)
|
The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of
the Registrant.
|
/s/ A. James Teague
|
||
Name:
|
A. James Teague
|
|
Title:
|
Co-Chief Executive Officer of Enterprise Products Holdings LLC, the General Partner of Enterprise Products Partners L.P.
|
(1)
|
The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of
the Registrant.
|
/s/ W. Randall Fowler
|
||
Name:
|
W. Randall Fowler
|
|
Title:
|
Co-Chief Executive Officer and Chief Financial Officer of Enterprise Products Holdings LLC, the General Partner of Enterprise Products Partners L.P.
|
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
ASSETS | ||
Accounts receivable, allowance for doubtful accounts | $ 46.5 | $ 12.4 |
Intangible assets, accumulated amortization | $ 1,826.7 | $ 1,687.5 |
Redeemable preferred limited partner interests: | ||
Series A cumulative convertible preferred units outstanding (in units) | 50,138 | |
Limited partners: | ||
Common units issued (in units) | 2,182,308,958 | 2,189,226,130 |
Common units outstanding (in units) | 2,182,308,958 | 2,189,226,130 |
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME | |||
Net income | $ 3,885.7 | $ 4,687.1 | $ 4,238.5 |
Commodity hedging derivative instruments: | |||
Changes in fair value of cash flow hedges | 124.4 | 44.1 | 293.2 |
Reclassification of gains to net income | (272.7) | (141.7) | (130.4) |
Interest rate hedging derivative instruments: | |||
Changes in fair value of cash flow hedges | (127.5) | 81.4 | 22.2 |
Reclassification of losses to net income | 39.3 | 37.3 | 38.1 |
Total cash flow hedges | (236.5) | 21.1 | 223.1 |
Other | (0.1) | (0.6) | (0.5) |
Total other comprehensive income (loss) | (236.6) | 20.5 | 222.6 |
Comprehensive income | 3,649.1 | 4,707.6 | 4,461.1 |
Comprehensive income attributable to noncontrolling interests | (110.1) | (95.8) | (66.1) |
Comprehensive income attributable to preferred units | (0.9) | 0.0 | 0.0 |
Comprehensive income attributable to common unitholders | $ 3,538.1 | $ 4,611.8 | $ 4,395.0 |
Partnership Organization and Operations |
12 Months Ended | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2020 | |||||||||||||
Partnership Organization and Operations [Abstract] | |||||||||||||
Partnership Organization and Operations |
KEY REFERENCES USED IN THESE
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unless the context requires otherwise, references to “we,” “us,” or “our” within these Notes to Consolidated Financial Statements are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.
References to the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis.
References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.
The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.
References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.
We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding and 30.2% of its preferred units outstanding at December 31, 2020.
All statistical data (e.g., pipeline mileage, processing capacity and similar operating metrics) in these notes to consolidated financial statements are unaudited.
With the exception of per unit amounts, or as noted within the context of each disclosure,
the dollar amounts presented in the tabular data within these disclosures are
stated in millions of dollars.
Note 1. Partnership Organization and Operations
We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.
Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include:
Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. See Note 15 for information regarding related party matters.
Our operations are reported under four business segments: NGL Pipelines & Services, Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and Petrochemical & Refined Products Services. See Note 10 for additional information regarding our business segments.
|
Summary of Significant Accounting Policies |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Significant Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Significant Accounting Policies |
Note 2. Summary of Significant Accounting Policies
Our consolidated financial statements are prepared on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles (“GAAP”).
Allowance for Doubtful Accounts
We estimate our allowance for doubtful accounts at each reporting date using a current expected credit loss model, which requires the measurement of expected credit losses for financial assets (e.g., accounts receivable) based on historical experience with customers, current economic conditions, and reasonable and supportable forecasts. We may also increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties.
The following table presents our allowance for doubtful accounts activity for the years indicated:
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.
Restricted cash primarily represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil, refined products and power. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 14 for information regarding our derivative instruments and hedging activities.
The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows.
Consolidation Policy
Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 8 for information regarding noncontrolling interests.
If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts.
Contingencies
Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when 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.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 17 for additional information regarding our contingencies.
Current Assets and Current Liabilities
We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and current liabilities, respectively.
Derivative Instruments
We use derivative instruments such as futures, swaps, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether forecasted transactions are probable of occurring in the future.
We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of:
An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period.
A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings.
Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting.
For certain physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future. See Note 14 for additional information regarding our derivative instruments.
Environmental Costs
Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2020, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable.
The following table presents the activity of our environmental reserves for the years indicated:
At December 31, 2020 and 2019, $3.8 million and $5.8 million, respectively, of our environmental reserves were classified as current liabilities.
Estimates
Preparing our consolidated financial statements in conformity with U.S. GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.
Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.
Fair Value Measurements
Our recurring and nonrecurring fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques (such as the income or market approaches) employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible.
A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2 fair value measures) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3 fair value measures). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:
With regards to commodity derivatives, our Level 3 fair values primarily consist of the following commodity derivative instruments used to hedge various inventories and transportation capacities: (i) NGL-based contracts with terms greater than one year; (ii) crude, natural gas and refined products-based contracts with terms greater than 36 months; (iii) over-the-counter options; and (iv) exchange traded options with terms greater than one year. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments.
Our nonrecurring fair value estimates are generally based on the income approach to fair value and reflect various Level 3 inputs. In many cases, there are no active markets (a Level 1 fair value measure) to rely on or other similar recent transactions (a Level 2 fair value measure) to compare to. Our nonrecurring fair value estimates often include management’s expectations of the residual market values for the underlying assets based on their knowledge and experience in the industry (a Level 3 fair value measure). Other examples of Level 3 inputs used in the valuation models include anticipated gross operating margins, throughput or processing volumes, utilization factors, sustaining capital expenditures, discount rates and business growth rates. When probability weights are used in cash flow modeling, the weights are generally obtained from management personnel having oversight responsibilities for the assets being tested.
Impairment Testing
The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated:
Asset impairment charges related to operations are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations.
The following information describes our accounting policies regarding impairment testing for major asset categories:
We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets comprising the reporting unit, which, in turn, rely on management’s estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit’s cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. We believe that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates. See Note 6 for information regarding an impairment charge attributable to goodwill in 2020.
We are closely monitoring the recoverability of our long-lived assets, investments in unconsolidated affiliates and goodwill in light of the adverse economic effects of the coronavirus disease 2019 (“COVID-19”) pandemic. If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in the recognition of additional non-cash impairment charges in the future.
Inventories
Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 3 for additional information regarding our inventories.
Leases
In February 2016, the FASB issued Accounting Standards Codification (“ASC”) 842, Leases, which requires substantially all leases be recorded on the balance sheet. We adopted the new standard on January 1, 2019 and applied it to (i) all new leases entered into after January 1, 2019 and (ii) all existing lease contracts as of January 1, 2019. ASC 842 supersedes existing lease accounting guidance found under ASC 840, Leases.
The new standard introduces two lessee accounting models, which results in a lease being classified as either a “finance” or “operating” lease based on whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with ASC 840 lease accounting guidance. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying asset for a specified period of time) and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs.
The subsequent measurement of each type of lease varies. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the effective interest method. Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis.
ASC 842 resulted in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we recognized a $246.1 million ROU asset and a corresponding lease liability based on the present value of then existing long-term operating lease obligations. In addition, we elected to apply several practical expedients and made accounting policy elections upon adoption of ASC 842 including:
See Note 17 for our disclosures regarding operating lease obligations.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period.
We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.
In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. With respect to midstream energy assets such as natural gas gathering systems that are reliant upon a specific natural resource basin for throughput volumes, the anticipated useful economic life of such assets may be limited by the estimated life of the associated natural resource basin from which the assets derive benefit. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes.
Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms.
Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any.
Certain of our plant facilities undergo periodic planned outages for major maintenance activities. The method of accounting for these activities depends on whether the plant utilizes either a distillation-based or reaction-based process. Our natural gas processing plants, NGL fractionators, deisobutanizers, propylene splitters and similar facilities utilize thermal distillation processes to separate hydrocarbons into more useful components. Our reaction-based plants, which primarily include our PDH, isomerization and octane enhancement facilities, utilize catalysts to facilitate chemical reactions that convert lower value hydrocarbons into higher value products. We use the expense-as-incurred method to account for the planned major maintenance activities of distillation-based plants. 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. We adopted the deferral method for our reaction-based plants in November 2020. Historically, the costs of major maintenance activities attributable to our reaction-based facilities, principally our octane enhancement assets, were not material to our consolidated financial statements.
With regard to the planned major maintenance activities of our marine transportation assets and underground storage caverns, we continue to use the deferral method to account for such costs.
Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.
See Note 4 for additional information regarding our property, plant and equipment and AROs.
Revenues
Substantially all of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers, however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases, ASC 845, Nonmonetary Transactions, or ASC 815, Derivatives and Hedging Activities.
The core principle of ASC 606 is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. We apply this core principle by following five key steps outlined in ASC 606: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.
Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet.
Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from its use of, the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer.
Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements. The terms of our billings are typical of the industry for the products we sell.
Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation.
Customers may contribute funds to us to help offset the construction costs related to pipeline construction activities and production well tie-ins. These receipts are recognized as additional service revenues over the term of the associated midstream services provided to the customer.
For those contracts under which we have the ability to invoice the customer in an amount that corresponds directly with the value of the performance obligation completed to date, we recognize revenue as we have the right to invoice.
See Note 9 regarding our revenue disclosures.
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Inventories |
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Inventories |
Note 3. Inventories
Our inventory amounts by product type were as follows at the dates indicated:
Inventories of NGLs, refined products and crude oil increased since December 31, 2019 primarily due to the use of working capital in connection with our marketing activities.
In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to outright purchases from third parties for cash), these volumes are valued at market-based prices during the month in which they are acquired.
The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the years indicated:
Due to fluctuating commodity prices, we recognize lower of cost or net realizable value adjustments when the carrying value of our available-for-sale inventories exceeds their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. To the extent our commodity hedging strategies address inventory-related price risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 14 for a description of our commodity hedging activities.
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Property, Plant and Equipment |
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Property, Plant and Equipment |
Note 4. Property, Plant and Equipment
The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:
The following table summarizes our depreciation expense and capitalized interest amounts for the years indicated:
Asset Retirement Obligations
We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. Our contractual AROs primarily result from right-of-way agreements associated with our pipeline operations and property leases associated with our plant sites. In addition, we record AROs in connection with governmental regulations associated with the abandonment or retirement of above-ground brine storage pits and certain marine vessels. We also record AROs in connection with regulatory requirements associated with the renovation or demolition of certain assets containing hazardous substances such as asbestos. We typically fund our AROs using cash flow from operations.
Property, plant and equipment at December 31, 2020 and 2019 includes $69.7 million and $69.6 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset.
The following table presents information regarding our AROs for the years indicated:
The following table presents our forecast of ARO-related accretion expense for the years indicated:
Impairments of Property, Plant and Equipment
The following table presents our non-cash asset impairment charges involving property, plant and equipment by business segment for the years indicated:
The following information summarizes our significant asset impairment charges involving property, plant and equipment that were recognized during the year ended December 31, 2020:
For information regarding our non-recurring fair value estimates for the marine transportation business and our South Texas natural gas gathering and processing assets, see Note 14.
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Investments in Unconsolidated Affiliates |
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Investments in Unconsolidated Affiliates |
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 (loss) of unconsolidated affiliates by business segment for the years indicated:
Impairment of Investment in Unconsolidated Affiliate
In December 2019, we recorded a $76.4 million impairment charge to fully write off our 50% equity method investment in Centennial Pipeline LLC (“Centennial”), which owns the idled Centennial Pipeline and related terminal infrastructure. Due to declines in the viability of potential commercial transactions involving this former refined products pipeline, we concluded that our investment was not recoverable and had no fair value at December 31, 2019. The impairment charge is a component of operating costs and expenses for the year ended December 31, 2019 as presented on our Statements of Consolidated Operations. We continue to own a 50% equity interest in the Centennial Pipeline, which is being maintained in an idled state in accordance with governmental regulations.
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Intangible Assets and Goodwill |
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Intangible Assets and Goodwill |
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, 2020, the carrying value of our portfolio of customer relationship intangible assets was $3.08 billion, the principal components of which were as follows:
In December 2020, we recognized $5.6 million of impairment charges attributable to customer relationship intangible assets in connection with our writedowns of the marine transportation business and certain South Texas natural gas processing and gathering assets (see Note 4).
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, 2020, the carrying value of our portfolio of contract-based intangible assets was $228.0 million, the principal components of which were as follows:
Impairment of Goodwill
Goodwill represents the cost of acquired businesses in excess of the fair value of their net assets at acquisition. Our goodwill balance was $5.45 billion and $5.75 billion at December 31, 2020 and 2019, respectively.
Based on our most recent goodwill impairment test at December 31, 2020, the estimated fair value of each of our reporting units, with the exception of our natural gas pipelines and services reporting unit (as described below), was at least 10% in excess of its carrying value. The following table presents changes in the carrying amount of goodwill by business segment during the periods indicated:
In December 2020, management determined that the carrying value of our natural gas pipelines and services reporting unit exceeded its estimated fair value. This reporting unit, which reflects the operations of our Natural Gas Pipelines & Services business segment, includes our natural gas gathering and transmission pipelines, storage facilities and related marketing activities. The long-term outlook for natural gas production in certain supply basins such as the Rocky Mountains and East Texas is expected to remain lower for longer due to reduced drilling activity. In addition, the decline in pipeline revenues attributable to lower regional natural gas price spreads is expected to adversely impact the future cash flows of our transmission pipelines. These factors, coupled with an increase in the estimated rate of return required for such businesses by market participants, resulted in the fair value of this reporting unit being less than its carrying value at December 31, 2020. The resulting goodwill impairment charge of $296.3 million represents the entire amount of goodwill attributable to this reporting unit and is reflected as a component of operating costs and expenses for the year ended December 31, 2020 as presented on our Statements of Consolidated Operations.
We did not record any goodwill impairment charges during the years ended December 31, 2019 or 2018.
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Debt Obligations |
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.
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, 2020:
Amounts borrowed under EPO’s 364-Day and Multi-Year Revolving Credit Agreements bear interest, at its election, equal to: (i) LIBOR, plus an additional variable spread; or (ii) an alternate base rate, which is the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) the LIBO Market Index Rate in effect on such day plus 1% and a variable spread. The applicable spreads are determined based on EPO's debt ratings.
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. Financial industry working groups are developing replacement rates and methodologies to transition existing agreements that depend on LIBOR as a reference rate. We currently do not expect the transition from LIBOR to have a material impact on us.
The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2020 for the next five years, and in total thereafter:
In February 2021, EPO notified its trustee and paying agent to redeem all of the $575.0 million outstanding principal amount of its Senior Notes RR effective as of March 15, 2021 (one month prior to their scheduled maturity in April 2021). These notes are redeemable at EPO’s election at par (i.e., at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon). On a short term basis, the redemption of EPO’s Senior Notes RR is expected to be made using proceeds from the issuance of short term notes under EPO’s commercial paper program.
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 available borrowing capacity under EPO’s Multi-Year Revolving Credit Agreement equal to the aggregate amount outstanding under our commercial paper notes. All commercial paper notes issued under the program are senior unsecured obligations of EPO that are unconditionally guaranteed by the Partnership. As of December 31, 2020, EPO had no short-term notes outstanding under its commercial paper program.
364-Day Revolving Credit Agreements
In September 2020, EPO entered into a new 364-Day Revolving Credit Agreement (the “September 2020 364-Day Revolving Credit Agreement”) that replaced its September 2019 364-Day Revolving Credit Agreement. Under the terms of the September 2020 364-Day Revolving Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein. The September 2020 364-Day Revolving Credit Agreement matures in September 2021. To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as non-revolving term loans for a period of one additional year, payable in September 2022. Borrowings under the September 2020 364-Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.
The September 2020 364-Day Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement. The September 2020 364-Day Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.
EPO’s obligations under the September 2020 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership.
Multi-Year Revolving Credit Agreement
EPO has entered into a multi-year revolving credit agreement (as amended, the “Multi-Year Revolving Credit Agreement”) that provides for a borrowing capacity of $3.5 billion, which may be increased by up to $500 million to $4.0 billion at EPO’s election provided certain conditions are met, with a maturity date of September 10, 2024. The maturity date may be extended at EPO’s request by up to two years, with the consent of required lenders as set forth under the credit agreement. Borrowings under the Multi-Year Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes.
The Multi-Year Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement. The Multi-Year Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom.
EPO’s obligations under the Multi-Year Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership.
Senior Notes
EPO’s fixed-rate senior notes are unsecured obligations of EPO that rank equal with its existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. EPO’s senior notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict its ability (with certain exceptions) to incur debt secured by liens and engage in sale and leaseback transactions. In total, EPO issued $4.25 billion, $2.5 billion and $5.0 billion of senior notes during the years ended December 31, 2020, 2019 and 2018, respectively.
In January 2020, EPO issued $3.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2030 (“Senior Notes AAA”), (ii) $1.0 billion principal amount of senior notes due January 2051 (“Senior Notes BBB”) and (iii) $1.0 billion principal amount of senior notes due January 2060 (“Senior Notes CCC”). Senior Notes AAA were issued at 99.921% of their principal amount and have a fixed rate of interest of 2.80% per year. Senior Notes BBB were issued at 99.413% of their principal amount and have a fixed rate of interest of 3.70% per year. Senior Notes CCC were issued at 99.360% of their principal amount and have a fixed rate of interest of 3.95% per year. Net proceeds from the January 2020 senior notes offering were used by EPO for the repayment of $500.0 million principal amount of its Senior Notes Q that matured in January 2020, the repayment of amounts outstanding under its commercial paper program and for general company purposes. In addition, net proceeds from this offering were used by EPO for the repayment of $1.0 billion principal amount of its Senior Notes Y that matured in September 2020.
In August 2020, EPO issued $1.0 billion in principal amount of senior notes due February 2052 (“Senior Notes DDD”) and $250.0 million in principal amount of reopened Senior Notes AAA. The reopened Senior Notes AAA form a single series with the original notes of that series, trade under the same CUSIP number, and have the same terms as to status, redemption or otherwise as the original notes of that series. The reopened Senior Notes AAA were issued at 107.211% of their principal amount and have a fixed rate of interest of 2.80% per year. Senior Notes DDD were issued at 99.233% of their principal amount and have a fixed rate of interest of 3.20% per year. Net proceeds from the issuance of these senior notes were used for general company purposes, including for growth capital investments, and to repay a portion of the $750.0 million in principal amount of Senior Notes TT that matured in February 2021.
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. EPO issued $700.0 million of junior notes during the year ended December 31, 2018.
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.
EPO repurchased and retired $24.2 million in principal amount of its Junior Subordinated Notes C in 2019. A $1.5 million gain on the extinguishment of these debt obligations is included in “Other, net” on our Statements of Consolidated Operations with respect to the year ended December 31, 2019.
Letters of Credit
At December 31, 2020, EPO had $200.7 million of letters of credit outstanding primarily related to our commodity hedging activities.
Lender Financial Covenants
We were in compliance with the financial covenants of our consolidated debt agreements at December 31, 2020.
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Capital Accounts |
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Equity and Distributions |
Note 8. Capital Accounts
Common Limited Partner Interests
The following table summarizes changes in the number of our common units outstanding since December 31, 2017:
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 (the “2019 Shelf”) on file with the SEC which allows the Partnership and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. EPO issued $4.25 billion of senior notes during 2020 using the 2019 Shelf (see Note 7).
In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to $2.54 billion of its common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program). The Partnership did not issue any common units under its ATM program during the three years ended December 31, 2020. The Partnership’s capacity to issue additional common units under the ATM program remains at $2.54 billion as of December 31, 2020.
We may issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to capital investments.
Issuance of Common Units due to Settlement of Liquidity Option in March 2020
In October 2014, we acquired approximately 65.9% of the limited partner interests of Oiltanking Partners, L.P. (“Oiltanking”), all of the member interests of OTLP GP, LLC, the general partner of Oiltanking (“Oiltanking GP”), and the incentive distribution rights held by Oiltanking GP from Oiltanking Holding Americas, Inc. (currently known as OTA Holdings, Inc., “OTA”), a U.S. corporation, as the first step (“Step 1”) of a two-step acquisition of Oiltanking. In February 2015, we completed the second step of this transaction consisting of the acquisition of the noncontrolling interests in Oiltanking. In order to fund the equity consideration paid in Step 1 of the Oiltanking acquisition, we issued 54,807,352 common units to OTA on October 1, 2014 in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereof. We also entered into a put option agreement (the “Liquidity Option Agreement” or “Liquidity Option”) with OTA and Marquard & Bahls AG (“M&B”), a German corporation and the ultimate parent company of OTA, in connection with Step 1. Under the Liquidity Option Agreement, we granted M&B the option to sell to the Partnership 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020.
On February 25, 2020, the Partnership received notice of M&B’s election to exercise its rights under the Liquidity Option Agreement. On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement by issuing 54,807,352 new common units to Skyline North Americas, Inc. (“Skyline,” an affiliate of M&B) in exchange for the capital stock of OTA. As a result of the settlement, OTA became a consolidated subsidiary of ours and we indirectly acquired the 54,807,352 Partnership common units owned by OTA and assumed all future income tax obligations of OTA, including its deferred tax liability.
As a result of the Liquidity Option settlement, the partners’ equity balance for common units (as presented on our Consolidated Balance Sheet) increased by $1.30 billion, representing the market value of the 54,807,352 Partnership common units issued to Skyline on March 5, 2020 at a closing price of $23.67 per unit. Since OTA did not meet the definition of a business as described in ASC 805, Business Combinations, the OTA transaction was accounted for by the Partnership as the reacquisition of common units and the assumption of OTA’s related deferred tax liability. In consolidation, we present the common units owned by OTA as treasury units, with their historical cost equal to the $1.30 billion market value of the Partnership common units issued to Skyline. On September 30, 2020, OTA exchanged the common units it holds for preferred units issued by the Partnership. For information regarding the preferred units and exchange transaction, see “Redeemable Preferred Limited Partner Interests” within this Note 8.
The common units issued to Skyline upon settlement of the Liquidity Option constitute “restricted securities” in the meaning of Rule 144 under the Securities Act and may not be resold except pursuant to an effective registration statement or an available exemption under the Securities Act. In connection with the settlement of the Liquidity Option, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Skyline. Pursuant to the Registration Rights Agreement, Skyline has the right to request that the Partnership prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of the Partnership’s common units owned by Skyline and its affiliates. The Partnership’s obligation to Skyline to effect such transactions is limited to five registration statements and underwritten offerings. In May 2020, the Partnership filed a registration statement on behalf of Skyline for the resale of up to 54,807,352 common units. This registration statement is effective and, in June 2020, the Partnership filed a prospectus supplement to this registration statement that allows Skyline to sell up to $500 million of the Partnership’s common units it owns in connection with an “at-the-market” program that it administers. We do not receive any proceeds from such offerings.
Upon settlement of the Liquidity Option on March 5, 2020, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA as calculated in accordance with ASC 740, Income Taxes. See Note 16 for additional information regarding OTA’s deferred tax liability. For information regarding the Liquidity Option prior to its settlement, see Note 17.
Common Unit Repurchases Under Buyback Programs
In January 2019, we announced that the Board of Enterprise GP had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. No time limit has been set for completion of the program, and it may be suspended or discontinued at any time.
The Partnership repurchased 8,978,317 common units under the 2019 Buyback Program through open market and private purchases during the year ended December 31, 2020. The total purchase price of these repurchases was $186.3 million including commissions and fees. During the year ended December 31, 2019, the Partnership repurchased 2,909,128 common units under the 2019 Buyback Program for a total purchase price of $81.1 million including commissions and fees. Units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. At December 31, 2020, the remaining available capacity under the 2019 Buyback Program was $1.73 billion.
In December 1998, we announced a common unit buyback program whereby we, together with certain affiliates, could repurchase up to 4,000,000 of the Partnership’s common units on the open market (the “Legacy Buyback Program”). The Partnership purchased the remaining authorized amount of 1,236,800 common units in December 2018 for $30.8 million. Units repurchased under the Legacy Buyback Program were immediately cancelled upon acquisition.
Common Units Delivered Under DRIP and EUPP
The Partnership has registration statements on file with the SEC in connection with its distribution reinvestment plan (“DRIP”) and employee unit purchase plan (“EUPP”). In July 2019, the Partnership announced that, beginning with the quarterly distribution payment paid in August 2019, it would use common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP. This election is subject to change in future quarters depending on the Partnership’s need for equity capital. Agents of the Partnership purchased 6,982,963 common units and 2,801,196 common units on the open market and delivered them to participants in the DRIP and EUPP during the year ended December 31, 2020 and five months ended December 31, 2019, respectively. Apart from $2.4 million and $0.9 million attributable to the plan discount available to all participants in the EUPP during 2020 and 2019, respectively, the funds used to effect these purchases were sourced from the DRIP and EUPP participants. No other Partnership funds were used to satisfy these obligations. We used open market purchases to satisfy DRIP and EUPP reinvestments in connection with the distribution paid on February 11, 2021.
Prior to July 2019, the Partnership satisfied its delivery obligations under the DRIP and EUPP by issuing new common units to participants. An aggregate 2,897,990 common units and 19,861,951 common units were issued to DRIP and EUPP participants during the seven months ended July 31, 2019 and year ended December 31, 2018, respectively. These transactions generated net cash proceeds of $82.2 million in 2019 and $538.4 million in 2018. Privately held affiliates of EPCO reinvested $29 million and $213 million through the DRIP in each of the years ended December 31, 2019 and 2018, respectively (this amount being a component of the net cash proceeds presented for each period).
After taking into account the number of common units delivered under the DRIP through December 31, 2020, we have the capacity to deliver an additional 50,615,246 common units under this plan. Likewise, we have the capacity to deliver an additional 3,318,607 common units under the EUPP.
Common Units Issued in Connection With the Vesting of Phantom Unit Awards
After taking into account tax withholding requirements, the Partnership issued 3,162,095, 2,720,603 and 2,442,436 new common units to employees in connection with the vesting of phantom unit awards during the years ended December 31, 2020, 2019 and 2018, respectively. See Note 13 for information regarding our phantom unit awards.
Common Units Issued in Connection With Employee Compensation
In February 2019 and 2018, certain employees of EPCO received discretionary bonus payments, less any retirement plan deductions and applicable withholding taxes, for work performed on our behalf during the prior fiscal year (e.g., the bonus paid in February 2019 was with respect to the year ended December 31, 2018). The net dollar value of the bonus amounts was remitted to employees through the issuance of an equivalent value of newly issued Partnership common units under EPCO’s 2008 Enterprise Products Long-Term Incentive Plan (Third Amendment and Restatement) (referred to as the “2008 Plan”).
In February 2019, we issued 1,626,041 common units, which had a value of $45.6 million, in connection with the employee bonus awards. In February 2018, we issued 1,443,586 common units, which had a value of $39.1 million. The compensation expense associated with each bonus award was recognized during the year in which the work was performed.
Common Units Issued in Connection With Land Acquisition
In April 2018, we acquired land in the Houston, Texas area for $85.2 million. The consideration paid consisted of $55.2 million in cash with the balance funded by the issuance of 1,223,242 Partnership common units.
Redeemable Preferred Limited Partner Interests
The following table summarizes changes in the number of our preferred units outstanding during the year ended December 31, 2020:
On September 30, 2020, the Partnership issued and sold an aggregate of 50,000 Series A Cumulative Convertible Preferred Units in a private placement transaction. The preferred units represent a new class of limited partner interests authorized under the Partnership Agreement. The stated value of each preferred unit is $1,000 per unit. The total offering price for the preferred units was $50.0 million, of which $32.5 million was received in cash with the remaining $17.5 million funded through the exchange of 1,120,588 of the Partnership’s common units owned by the purchasers. Cash proceeds from the preferred unit offering include $15.0 million received from a privately held affiliate of EPCO for the purchase of 15,000 preferred units. Offering expenses were approximately $1.0 million.
Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by 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. The historical cost of the treasury units did not change as a result of the exchange and remains at the $1.30 billion recognized on March 5, 2020 in connection with settlement of the Liquidity Option.
As described in the Partnership Agreement, key terms of the preferred units include the following:
In November 2020, the Partnership made its first quarterly distribution to third party and related party preferred unitholders. The distribution was valued at $0.5 million, consisting of PIK distributions of 138 new preferred units and $0.3 million in cash.
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, 2020 presents the capital accounts of the third-party and related party purchasers of the preferred units as mezzanine equity since the terms of the preferred units allow for cash redemption by the holders in a Change of Control event, without regard to the likelihood of such an event. The preferred units held by OTA are presented as treasury units in consolidation since their ultimate disposition remains under the control of the Partnership.
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 14.
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 $110.1 million, $95.8 million and $66.1 million for the years ended December 31, 2020, 2019 and 2018, respectively.
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 7, 2021, we announced that the Board of Enterprise GP declared a quarterly cash distribution of $0.45 per common unit with respect to the fourth quarter of 2020. The quarterly distribution was paid on February 11, 2021 to unitholders of record as of the close of business on January 29, 2021. The total amount paid was $988.8 million, which includes $7.1 million for distribution equivalent rights on phantom unit awards.
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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 NGLs we receive under commodity-based contracts (once the processing service has been performed and we are entitled to such volumes). The value assigned to this non-cash consideration and related inventory is based on the market value of the equity NGLs at the time the services are performed. As noted previously, we also recognize product sales revenue, along with a corresponding cost of sales, when these NGLs are delivered and sold to downstream customers under NGL marketing contracts.
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.
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, 2020.
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.
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Business Segments |
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Business Segments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Segments |
Note 10. Business Segments and Related Information
Segment Overview
Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.
Financial information regarding these segments is evaluated regularly by our 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 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 segment (mileage and other statistics are unaudited):
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. Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base.
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 Mont Belvieu 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 related cost of sales amounts are explained in part by changes in energy commodity prices. In general, lower energy commodity prices result in a decrease in our revenues attributable to product sales; however, these lower commodity prices also decrease the associated cost of sales as purchase costs are lower. The same type of correlation would be true in the case of higher energy commodity sales prices and purchase costs.
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 (thus constituting a “major customer”) during the years ended December 31, 2020 or 2018. However, Vitol Holding B.V. and its affiliates (collectively, “Vitol”) accounted for $3.31 billion, or 10.1%, of our consolidated revenues during the year ended December 31, 2019. Vitol is a global energy and commodity trading company. The following table presents our consolidated revenues from Vitol by business segment for the year ended December 31, 2019:
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Earnings Per Unit |
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Earnings Per Unit |
Note 11. Earnings Per Unit
The following table presents our calculation of basic and diluted earnings per common unit for the years indicated:
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Business Combinations |
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Business Combinations |
Note 12. Business Combinations
Acquisition of Delaware Processing
In March 2018, we acquired the remaining 50% member interest in our former Delaware Processing joint venture for $151 million in cash, net of $3.9 million of cash held by the venture. As a result, Delaware Processing became a wholly-owned consolidated subsidiary of ours. Delaware Processing owns a cryogenic natural gas processing facility having a capacity of 150 million cubic feet per day (“MMcf/d”). The facility, which is located in Reeves County, Texas and entered service in August 2016, serves producers in the Delaware Basin in West Texas and southern New Mexico.
The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Delaware Processing acquisition.
Prior to this acquisition, we accounted for our investment using the equity method. On a historical pro forma basis, our consolidated revenues, costs and expenses, operating income, net income attributable to Enterprise Products Partners L.P. and earnings per unit amounts for the year ended December 31, 2018 would not have differed materially from those we reported had the acquisition been completed on January 1, 2018 rather than March 29, 2018.
At March 29, 2018, our 50% equity investment in Delaware Processing was recorded at $107.0 million. Upon acquisition of the remaining 50% member interest, our existing equity investment was remeasured to fair value resulting in the recognition of a non-cash $39.4 million gain, which is presented within “Other income (expense)” on our Consolidated Statement of Operations for the year ended December 31, 2018.
The results for this business are reported under the NGL Pipelines & Services business segment.
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Equity-Based Awards |
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Equity-based Awards |
Note 13. Equity-Based Awards
An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the 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 common units upon vesting. Compensation expense for liability-classified awards is recognized over the requisite service or vesting period based on the fair value of the award remeasured at each reporting date. Liability-classified awards are settled in cash upon vesting.
Phantom Unit Awards
Subject to customary forfeiture provisions, phantom unit awards allow recipients to acquire EPD 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 EPD 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 phantom unit awards were granted under the 2008 Plan, which is a long-term incentive plan under which any employee or consultant of EPCO, us or our affiliates that provides services to us, directly or indirectly, may receive incentive compensation awards in the form of phantom units, options, restricted common units, unit appreciation rights, unit awards, other unit-based awards or substitute awards. Non-employee directors of our general partner may also participate in the 2008 Plan.
The maximum number of EPD common units authorized for issuance under the 2008 Plan was 55,000,000 at December 31, 2020. This amount automatically increased under the terms of the 2008 Plan by 5,000,000 common units on January 1, 2021 and will continue to automatically increase annually on January 1 thereafter during the term of the 2008 Plan; provided, however, that in no event shall the maximum aggregate number exceed 70,000,000 common units. The 2008 Plan is effective until September 30, 2023 or, if earlier, until (i) the time that all available common units under the 2008 Plan have been delivered to participants or (ii) the time of termination of the 2008 Plan by the Board of Directors of EPCO or by the Incentive Plan Administration Subcommittee of the Governance Committee of Enterprise GP. After giving effect to awards granted under the 2008 Plan through December 31, 2020, a total of 16,229,995 additional common units were available for issuance. After taking into account tax withholding requirements, we issued 3,162,095, 2,720,603 and 2,442,436 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2020, 2019 and 2018, respectively.
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 EPD 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 $156.7 million at December 31, 2020, of which our share of such cost is currently estimated to be $129.6 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years.
Profits Interest Awards
In 2016 and 2018, EPCO Holdings Inc. (“EPCO Holdings”), a privately held affiliate of EPCO, contributed a portion of the EPD common units it owned to form limited partnerships (referred to as “Employee Partnerships”) that serve as long-term incentive arrangements for key employees of EPCO by providing them a “profits interest” in an Employee Partnership. The Employee Partnerships named (i) EPD PubCo Unit I L.P. (“PubCo I”), (ii) EPD PubCo Unit II L.P. (“PubCo II”), and (iii) EPD PrivCo Unit I L.P. (“PrivCo I”) were formed by EPCO Holdings in 2016. The Employee Partnerships named (i) EPD 2018 Unit IV L.P. (“EPD IV”) and (ii) EPCO Unit II L.P. (“EPCO II”) were formed by EPCO Holdings in 2018. The Class B limited partner interests of PubCo I vested in February 2020.
In September 2020, the partners of PubCo II and PrivCo I amended their respective limited partnership agreements to provide for the vesting of their Class B limited partner interests on the earlier of (i) February 22, 2023, (ii) the first date on or after September 30, 2020 on which the closing market price of the Partnership’s common units is equal to or greater than $25.41 per unit, (iii) a change of control event, or (iv) dissolution of the applicable Employee Partnership. As a result of these modifications, PubCo II and PrivCo I will recognize incremental compensation cost of $1.2 million and $0.5 million, respectively, through February 22, 2023.
In exchange for the contributions of EPD 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 EPD common units, receive a cash distribution from EPD as do EPD’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 EPD 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, 2020:
The fair value of each Employee Partnership (at either the grant date or modification date) is based on (i) the estimated value (as determined using a Black-Scholes option pricing model or Monte Carlo model, as applicable) of such Employee Partnership’s assets that would be distributed to the Class B limited partners thereof upon liquidation and (ii) the value, based on a discounted cash flow analysis, of the residual quarterly cash amounts that such Class B limited partners are expected to receive over the life of the 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.
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Hedging Activities and Fair Value Measurements |
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Derivative Instruments, Hedging Activities and Fair Value Measurements |
Note 14. Hedging Activities and Fair Value Measurements
In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.
Interest Rate Hedging Activities
We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), 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.
Swaptions
In 2019 and 2018, we sold options to be put into forward-starting swaps, or swaptions, if the market rate of interest fell below the strike rate of the option upon expiration of the derivative instrument. The premiums we realized upon sale of the swaptions are reflected as a $23.1 million and $29.4 million reduction in interest expense for the year ended December 31, 2019 and 2018, respectively.
Due to declining interest rates, the counterparties to swaptions we sold in July 2019 exercised their right to put us into ten forward-starting swaps in September 2019 having an aggregate notional value of $1.0 billion. Since the swaptions were not designated as hedging instruments and were subject to mark-to-market accounting, we incurred an unrealized, mark-to-market loss at inception of the forward-starting swaps totaling $94.9 million that is reflected as an increase in interest expense for the year ended December 31, 2019. The ten forward-starting swaps resulting from the swaption exercise in September 2019 were designated as hedging instruments and are subject to cash flow hedge accounting.
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 (based on LIBOR or an equivalent index rate) on the same notional amount.
The following table summarizes our portfolio of 30-year forward-starting swaps at December 31, 2020, all of which are associated with the expected future issuance of senior notes.
In total, the notional amount of forward-starting swaps outstanding at December 31, 2020 was $1.08 billion. The weighted-average fixed interest rate of these derivative instruments is 1.83%.
As a result of market conditions, we terminated an aggregate $575 million notional amount of forward-starting swaps in 2020, which resulted in net cash payments of $33.3 million. As cash flow hedges, losses on these derivative instruments are reflected as a component of accumulated other comprehensive loss and are being amortized to earnings (as an increase in interest expense) over the 30-year life of the associated debt through January 2051. These swaps were unwound in connection with our issuance of Senior Notes BBB. During 2018, we terminated an aggregate $275 million notional amount of forward-starting swaps, which resulted in cash proceeds totaling $22.1 million. As cash flow hedges, gains on these derivative instruments are reflected as a component of accumulated other comprehensive income and are being amortized to earnings (as a decrease in interest expense) over the 30-year life of the associated debt through February 2049.
Commodity Hedging Activities
The prices of natural gas, NGLs, crude oil, petrochemicals and refined products are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps.
At December 31, 2020, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins and (iii) hedging the fair value of commodity products held in inventory.
The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2020 (volume measures as noted):
The carrying amount of our inventories subject to fair value hedges was $144.0 million and $31.7 million at December 31, 2020 and 2019, respectively.
Certain basis swaps, basis spread options and other derivative instruments not designated as hedging instruments are used to manage market risks associated with anticipated purchases and sales of commodity products. There is some uncertainty involved in the timing of these transactions often due to the development of more favorable profit opportunities or when spreads are insufficient to cover variable costs thus reducing the likelihood that the transactions will occur during the periods originally forecasted. In accordance with derivatives accounting guidance, these instruments do not qualify for hedge accounting even though they are effective at managing the risk exposures of the underlying assets. Due to volatility in commodity prices, any non-cash, mark-to-market earnings variability cannot be predicted.
Tabular Presentation of Fair Value Amounts, and Gains and Losses on
Derivative Instruments and Related Hedged Items
The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:
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 $41.2 million of losses attributable to interest rate derivative instruments from accumulated other comprehensive loss to earnings as an increase in interest expense. Likewise, we expect to reclassify $35.6 million of losses attributable to commodity derivative instruments from accumulated other comprehensive loss to earnings, with $36.0 million as a decrease in revenue and $0.4 million as a decrease in operating costs and expenses.
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 $165.8 million gain recognized for the year ended December 31, 2020 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $92.1 million of realized gains and $73.7 million of net unrealized mark-to-market gains attributable to commodity derivatives.
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 and interest expense for the years indicated:
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 Chicago Mercantile Exchange (“CME”) Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.
In the aggregate, the fair value of our commodity hedging portfolios at December 31, 2020 was a net derivative liability of $568.8 million prior to the impact of CME Rule 814.
Prior to being settled on March 5, 2020, the recurring fair value measurement pertaining to the Liquidity Option was based on a number of Level 3 inputs. For information regarding the Liquidity Option prior to its settlement, see Note 17.
The following table sets forth a reconciliation of changes in the fair values of our recurring Level 3 financial assets and liabilities on a combined basis for the years indicated:
Nonrecurring Fair Value Measurements
We wrote down the assets comprising our marine transportation business and certain natural gas gathering and processing activities to their estimated fair values in 2020 (see Note 4). Apart from these matters, we did not have any significant nonrecurring fair value measurements during the years ended December 31, 2020, 2019 or 2018. The following table presents information regarding our significant nonrecurring fair value measurements at December 31, 2020:
Our fair value estimate of $410.0 million for the marine transportation business is based on the income approach to fair value, which relies on the use of a discounted cash flow model. Our valuation estimate for this business at December 31, 2020 incorporates several Level 3 inputs such as: (i) management’s long-term forecast of cash flows generated by the business; (ii) a discount rate of 9.3%; and (iii) a growth rate of 2.1% for terminal year cash flows. The discount rate used in this analysis is based on an estimated weighted-average cost of capital for market participants engaged in marine transportation activities.
Our fair value estimate for the South Texas natural gas gathering and processing assets of $21.3 million is based primarily on management expectations of the residual values of such facilities and pipelines based on historical experience.
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 $35.00 billion and $30.37 billion at December 31, 2020 and 2019, respectively. The aggregate carrying value of these debt obligations was $29.90 billion and $27.15 billion at December 31, 2020 and 2019, respectively. These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.
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Related Party Transactions |
Note 15. Related Party Transactions
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, 2020, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:
Of the total number of units held by EPCO and its privately held affiliates, 92,976,464 have been pledged as security under the credit facilities of EPCO and its privately held affiliates at December 31, 2020. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of EPD’s common units.
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 depend on the cash distributions they receive from us and other investments to fund their other activities and to meet their debt obligations. During the years ended December 31, 2020, 2019 and 2018, we paid EPCO and its privately held affiliates cash distributions totaling $1.21 billion, $1.19 billion and $1.16 billion, respectively.
From time-to-time, EPCO and its privately held affiliates elect to purchase additional common units under EPD’s DRIP and ATM program. During the years ended December 31, 2019 and 2018, privately held affiliates of EPCO reinvested $29 million and $213 million, respectively, through our DRIP. See Note 8 for additional information regarding our DRIP and ATM program.
We lease office space from privately held affiliates of EPCO at rental rates that approximate market rates. In January 2020, we amended an office space lease with an affiliate of EPCO that extended the term through June 2037. For the years ended December 31, 2020, 2019 and 2018, we recognized $13.0 million, $14.9 million and $13.9 million, respectively, of related party operating lease expense in connection with these office space leases.
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 18 for additional information regarding our insurance programs.
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:
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Income Taxes |
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Provision for Income Taxes |
Note 16. Income Taxes
Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in “qualifying income” (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2020, 2019 and 2018 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income tax on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests.
The following table presents the components of our consolidated benefit from (provision for) income taxes for the years indicated:
In addition to income tax amounts attributable to OTA (as described below), the provision for income taxes includes our state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”).
Income taxes are accounted for under the asset-and-liability method. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
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, 2020, 2019 and 2018.
OTA Deferred Tax Liability
On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement (see Note 8) and indirectly assumed OTA’s deferred tax liability, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014. Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes.
At March 5, 2020, the Liquidity Option liability amount was $511.9 million. Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income tax” line on our Statement of Consolidated Operations for the year ended December 31, 2020. OTA recognized an additional net, non-cash deferred income tax benefit of $83.1 million primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through September 30, 2020. In total, earnings for the year ended December 31, 2020 reflect $155.3 million of net deferred income tax benefit attributable to OTA.
On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $1,000 per unit (see Note 8). As a result and beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in the Partnership’s common units. Our subsidiary OTA is a corporation for U.S. federal income tax purposes, and the exchange of common units for preferred units did not constitute a taxable transaction for OTA.
Tabular Disclosures Regarding Income Taxes
Our federal, state and foreign income tax benefit (provision) is summarized below:
A reconciliation of the benefit from (provision for) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:
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:
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Commitments and Contingent Liabilities |
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Commitments and Contingencies |
Note 17. Commitments and Contingent Liabilities
Litigation
As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the Partnership in litigation matters.
Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued.
We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Based on a consideration of all relevant known facts and circumstances, we do not believe that the ultimate outcome of any currently pending litigation directed against us will have a material impact on our consolidated financial statements either individually at the claim level or in the aggregate.
At December 31, 2020 and 2019, our accruals for litigation contingencies were $6.1 million and $0.2 million, respectively, and were recorded in our Consolidated Balance Sheets as a component of “Other current liabilities.” Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to record additional accruals. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court.
PDH Litigation
In July 2013, we executed a contract with Foster Wheeler USA Corporation (“Foster Wheeler”) pursuant to which Foster Wheeler was to serve as the general contractor responsible for the engineering, procurement, construction and installation of our first propane dehydrogenation facility (“PDH 1”). In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation (“AFW”). In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH 1 project. In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC, to complete the construction and installation of PDH 1.
On September 2, 2016, we terminated AFW for cause and filed a lawsuit in the 151st Judicial Civil District Court of Harris County, Texas against AFW and its parent company, Amec Foster Wheeler plc, asserting claims for breach of contract, breach of warranty, fraudulent inducement, string-along fraud, gross negligence, professional negligence, negligent misrepresentation and attorneys’ fees. We intend to diligently prosecute these claims and seek all direct, consequential, and exemplary damages to which we may be entitled.
Redelivery Commitments
We store natural gas, crude oil, NGLs and certain petrochemical products owned by third parties under various agreements. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. At December 31, 2020, we had approximately 9.9 trillion British thermal units (“TBtus”) of natural gas, 19.4 MMBbls of crude oil, and 31.1 MMBbls of NGL and petrochemical products in our custody that were owned by third parties. We maintain insurance coverage in connection with such volumes that is consistent with our exposure. See Note 18 for information regarding insurance matters.
Commitments Under Equity Compensation Plans of EPCO
In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense attributable to employees who perform management, administrative and operating functions for us. See Notes 13 and 15 for additional information regarding our accounting for equity-based awards and related party information, respectively.
Contractual Obligations
The following table summarizes our various contractual obligations at December 31, 2020. 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, 2020, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are influenced by the long-term maturities of our $2.65 billion in junior subordinated notes (due June 2067 through February 2078). The estimated cash payments assume that (i) the junior subordinated notes are not repaid prior to their respective maturity dates and (ii) the amount of interest paid on the junior subordinated notes is based on either (a) the current fixed interest rate charged or (b) the weighted-average variable rate paid in 2020, as applicable, for each note through the respective maturity date. See Note 7 for information regarding fixed and weighted-average variable interest rates charged in 2020.
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 and NGLs, (iii) the lease of 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, 2020:
In total, our ROU asset and lease liability carrying values increased $121.8 million and $136.6 million, respectively, since December 31, 2019 primarily due to the modification of an office space lease with an affiliate of EPCO in 2020.
In total, operating lease expense was $102.0 million, $106.6 million and $86.4 million for the years ended December 31, 2020, 2019 and 2018, respectively. 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 $37.1 million and $48.1 million for the years ended December 31, 2020 and 2019, respectively.
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, 2020 and 2019 was $11.4 million and $14.4 million, respectively. We do not have any sales-type leases.
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:
Other Commitments
We are obligated to spend up to an aggregate $270 million over a ten-year period ending in 2025 on specified midstream gathering assets for certain producers utilizing our EFS Midstream System. If constructed, these new assets would be owned by us and be a component of the EFS Midstream System. As of December 31, 2020, we have spent $151 million of the $270 million commitment.
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:
Liquidity Option
Prior to its settlement on March 5, 2020, the Liquidity Option liability, at any measurement date, represented the fair value of estimated federal and state income taxes that we believe a market participant would assume due to ownership of OTA, including its deferred income tax liabilities. At December 31, 2019 and March 5, 2020, we estimated that our liability under the Liquidity Option Agreement, which was a component of “Other long-term liabilities” on our Consolidated Balance Sheet was $509.6 million and $511.9 million, respectively.
Our valuation estimates for the Liquidity Option liability at December 31, 2019 and March 5, 2020 incorporated several factors not readily observable in the market (i.e., Level 3 inputs) such as: (i) a discount rate of 5.7%; (ii) a blended federal and state income tax rate of approximately 22.8%; (iii) forecasted annual growth rates in our taxable earnings ranging from approximately 0.7% to 2.2%; (iv) allocations of Partnership income to OTA ranging from approximately 2.3% to 2.5%; and (v) the length of time that OTA is in existence following exercise of the option (up to 30 years).
Changes in the fair value of the Liquidity Option liability were recognized in earnings as a component of other expense on our Statements of Consolidated Operations. We recognized $2.3 million of non-cash accretion expense for the period January 1, 2020 to March 5, 2020 attributable to the Liquidity Option liability. Results for the years ended December 31, 2019 and 2018 include $119.6 million and $56.1 million, respectively, of expense attributable to accretion and changes in management estimates regarding inputs to the valuation model. The higher level of expense recognized in 2019 is primarily due to a decrease in the discount factor used in determining the present value of the liability since December 31, 2018. The discount rate is based on a weighted-average cost of capital, which declined over the course of 2019 due to lower U.S. interest rates.
For information regarding settlement of the Liquidity Option, see Note 8.
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Significant Risks and Uncertainties |
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Dec. 31, 2020 | |
Significant Risks and Uncertainties [Abstract] | |
Significant Risks and Uncertainties |
Note 18. Significant Risks and Uncertainties
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 EPD common units.
Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to a fire). Some of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired 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.
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Supplemental Cash Flow Information |
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Supplemental Cash Flow Information [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Cash Flow Information |
Note 19. Supplemental Cash Flow Information
The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the years indicated:
We incurred liabilities for construction in progress that had not been paid at December 31, 2020, 2019 and 2018 of $236.1 million, $432.0 million and $567.6 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Statements of Consolidated Cash Flows.
The following table presents our cash proceeds from asset sales for the years indicated:
The following table presents net gains attributable to asset sales for the years indicated:
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Summary of Significant Accounting Policies (Policies) |
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Allowance for Doubtful Accounts |
Allowance for Doubtful Accounts
We estimate our allowance for doubtful accounts at each reporting date using a current expected credit loss model, which requires the measurement of expected credit losses for financial assets (e.g., accounts receivable) based on historical experience with customers, current economic conditions, and reasonable and supportable forecasts. We may also increase the allowance for doubtful accounts in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties.
The following table presents our allowance for doubtful accounts activity for the years indicated:
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Cash, Cash Equivalents and Restricted Cash |
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.
Restricted cash primarily represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil, refined products and power. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 14 for information regarding our derivative instruments and hedging activities.
The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows.
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Consolidation Policy |
Consolidation Policy
Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 8 for information regarding noncontrolling interests.
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Contingencies |
Contingencies
Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when 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.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 17 for additional information regarding our contingencies.
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Current Assets and Current Liabilities |
Current Assets and Current Liabilities
We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and current liabilities, respectively.
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Derivative Instruments |
Derivative Instruments
We use derivative instruments such as futures, swaps, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether forecasted transactions are probable of occurring in the future.
We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of:
An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period.
A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings.
Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting.
For certain physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future. See Note 14 for additional information regarding our derivative instruments.
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Environmental Costs |
Environmental Costs
Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2020, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable.
The following table presents the activity of our environmental reserves for the years indicated:
At December 31, 2020 and 2019, $3.8 million and $5.8 million, respectively, of our environmental reserves were classified as current liabilities.
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Estimates |
Estimates
Preparing our consolidated financial statements in conformity with U.S. GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals.
Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.
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Fair Value Measurements |
Fair Value Measurements
Our recurring and nonrecurring fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques (such as the income or market approaches) employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible.
A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2 fair value measures) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3 fair value measures). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:
With regards to commodity derivatives, our Level 3 fair values primarily consist of the following commodity derivative instruments used to hedge various inventories and transportation capacities: (i) NGL-based contracts with terms greater than one year; (ii) crude, natural gas and refined products-based contracts with terms greater than 36 months; (iii) over-the-counter options; and (iv) exchange traded options with terms greater than one year. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments.
Our nonrecurring fair value estimates are generally based on the income approach to fair value and reflect various Level 3 inputs. In many cases, there are no active markets (a Level 1 fair value measure) to rely on or other similar recent transactions (a Level 2 fair value measure) to compare to. Our nonrecurring fair value estimates often include management’s expectations of the residual market values for the underlying assets based on their knowledge and experience in the industry (a Level 3 fair value measure). Other examples of Level 3 inputs used in the valuation models include anticipated gross operating margins, throughput or processing volumes, utilization factors, sustaining capital expenditures, discount rates and business growth rates. When probability weights are used in cash flow modeling, the weights are generally obtained from management personnel having oversight responsibilities for the assets being tested.
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Impairment Testing |
Impairment Testing
The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated:
Asset impairment charges related to operations are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations.
The following information describes our accounting policies regarding impairment testing for major asset categories:
We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets comprising the reporting unit, which, in turn, rely on management’s estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit’s cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. We believe that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates. See Note 6 for information regarding an impairment charge attributable to goodwill in 2020.
We are closely monitoring the recoverability of our long-lived assets, investments in unconsolidated affiliates and goodwill in light of the adverse economic effects of the coronavirus disease 2019 (“COVID-19”) pandemic. If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in the recognition of additional non-cash impairment charges in the future.
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Inventories |
Inventories
Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 3 for additional information regarding our inventories.
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Leases |
Leases
In February 2016, the FASB issued Accounting Standards Codification (“ASC”) 842, Leases, which requires substantially all leases be recorded on the balance sheet. We adopted the new standard on January 1, 2019 and applied it to (i) all new leases entered into after January 1, 2019 and (ii) all existing lease contracts as of January 1, 2019. ASC 842 supersedes existing lease accounting guidance found under ASC 840, Leases.
The new standard introduces two lessee accounting models, which results in a lease being classified as either a “finance” or “operating” lease based on whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria, four of which are generally consistent with ASC 840 lease accounting guidance. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying asset for a specified period of time) and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs.
The subsequent measurement of each type of lease varies. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the effective interest method. Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis.
ASC 842 resulted in changes to the way our operating leases are recorded, presented and disclosed in our consolidated financial statements. Upon adoption of ASC 842 on January 1, 2019, we recognized a $246.1 million ROU asset and a corresponding lease liability based on the present value of then existing long-term operating lease obligations. In addition, we elected to apply several practical expedients and made accounting policy elections upon adoption of ASC 842 including:
See Note 17 for our disclosures regarding operating lease obligations.
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Property, Plant and Equipment |
Property, Plant and Equipment
Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period.
We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise.
In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. With respect to midstream energy assets such as natural gas gathering systems that are reliant upon a specific natural resource basin for throughput volumes, the anticipated useful economic life of such assets may be limited by the estimated life of the associated natural resource basin from which the assets derive benefit. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes.
Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms.
Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any.
Certain of our plant facilities undergo periodic planned outages for major maintenance activities. The method of accounting for these activities depends on whether the plant utilizes either a distillation-based or reaction-based process. Our natural gas processing plants, NGL fractionators, deisobutanizers, propylene splitters and similar facilities utilize thermal distillation processes to separate hydrocarbons into more useful components. Our reaction-based plants, which primarily include our PDH, isomerization and octane enhancement facilities, utilize catalysts to facilitate chemical reactions that convert lower value hydrocarbons into higher value products. We use the expense-as-incurred method to account for the planned major maintenance activities of distillation-based plants. 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. We adopted the deferral method for our reaction-based plants in November 2020. Historically, the costs of major maintenance activities attributable to our reaction-based facilities, principally our octane enhancement assets, were not material to our consolidated financial statements.
With regard to the planned major maintenance activities of our marine transportation assets and underground storage caverns, we continue to use the deferral method to account for such costs.
Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.
See Note 4 for additional information regarding our property, plant and equipment and AROs.
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Revenue [Policy Text Block] |
Revenues
Substantially all of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers, however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases, ASC 845, Nonmonetary Transactions, or ASC 815, Derivatives and Hedging Activities.
The core principle of ASC 606 is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. We apply this core principle by following five key steps outlined in ASC 606: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.
Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet.
Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from its use of, the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer.
Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements. The terms of our billings are typical of the industry for the products we sell.
Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation.
Customers may contribute funds to us to help offset the construction costs related to pipeline construction activities and production well tie-ins. These receipts are recognized as additional service revenues over the term of the associated midstream services provided to the customer.
For those contracts under which we have the ability to invoice the customer in an amount that corresponds directly with the value of the performance obligation completed to date, we recognize revenue as we have the right to invoice.
See Note 9 regarding our revenue disclosures.
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Summary of Significant Accounting Policies (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Significant Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Allowance for Doubtful Accounts Activity |
The following table presents our allowance for doubtful accounts activity for the years indicated:
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Cash, Cash Equivalents and Restricted Cash |
The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows.
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Environmental Reserves Activity |
The following table presents the activity of our environmental reserves for the years indicated:
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Asset Impairment Charges |
The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated:
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Inventories (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Inventories [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Inventory Amounts by Product Type |
Our inventory amounts by product type were as follows at the dates indicated:
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Cost of Sales and Lower of Cost or Market Adjustments |
The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the years indicated:
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Property, Plant and Equipment (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment and Accumulated Depreciation |
The historical costs of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:
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Depreciation Expense and Capitalized Interest |
The following table summarizes our depreciation expense and capitalized interest amounts for the years indicated:
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AROs |
The following table presents information regarding our AROs for the years indicated:
The following table presents our forecast of ARO-related accretion expense for the years indicated:
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Impairments of Property, Plant and Equipment |
The following table presents our non-cash asset impairment charges involving property, plant and equipment by business segment for the years indicated:
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Investments in Unconsolidated Affiliates (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investments in Unconsolidated Affiliates [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investments in Unconsolidated Affiliates |
The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method.
The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the years indicated:
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Intangible Assets and Goodwill (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Intangible Assets and Goodwill [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Intangible Assets by Segment |
The following table summarizes our intangible assets by business segment at the dates indicated:
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Amortization Expense of Intangible Assets by Segment |
The following table presents the amortization expense of our intangible assets by business segment for the years indicated:
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Forecasted Amortization Expense |
The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated:
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Significant Acquired Intangible Assets |
At December 31, 2020, the carrying value of our portfolio of customer relationship intangible assets was $3.08 billion, the principal components of which were as follows:
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Schedule of Goodwill |
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Debt Obligations (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Debt Obligations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Consolidated Debt Obligations |
The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated:
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, 2020:
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Consolidated Debt Maturities |
The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2020 for the next five years, and in total thereafter:
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Capital Accounts (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capital Accounts [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Changes in Outstanding Units |
The following table summarizes changes in the number of our common units outstanding since December 31, 2017:
The following table summarizes changes in the number of our preferred units outstanding during the year ended December 31, 2020:
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Components of Accumulated Other Comprehensive Income (Loss) |
The following tables present the components of accumulated other comprehensive income (loss) as reported on our Consolidated Balance Sheets at the dates indicated:
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Reclassifications out of Accumulated Other Comprehensive Income (Loss) Into Net Income |
The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the years indicated:
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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:
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Declared Quarterly Cash Distribution Rates |
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.
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Revenues (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenues by Business Segment and Revenue Type |
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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:
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Remaining Performance Obligations |
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Business Segments (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Segments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Measurement of Total Segment Gross Operating Margin |
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.
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Information by Business Segments |
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:
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:
Information by business segment, together with reconciliations to our Consolidated Balance Sheet totals, is presented in the following table:
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Consolidated Revenues and Expenses |
The following table presents additional information regarding our consolidated revenues and costs and expenses for the years indicated:
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 (thus constituting a “major customer”) during the years ended December 31, 2020 or 2018. However, Vitol Holding B.V. and its affiliates (collectively, “Vitol”) accounted for $3.31 billion, or 10.1%, of our consolidated revenues during the year ended December 31, 2019. Vitol is a global energy and commodity trading company. The following table presents our consolidated revenues from Vitol by business segment for the year ended December 31, 2019:
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Earnings Per Unit (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Unit [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basic and Diluted Earnings Per Unit |
The following table presents our calculation of basic and diluted earnings per common unit for the years indicated:
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Business Combinations (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Allocation of Total Purchase Prices Paid in Connection with Business Combinations |
The following table presents the final fair value allocation of assets acquired and liabilities assumed in the Delaware Processing acquisition.
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Equity-Based Awards (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity-based Awards [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity-based Award Expense |
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:
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Other Share-based Compensation Plans |
The following table presents phantom unit award activity for the years indicated:
The following table presents supplemental information regarding phantom unit awards for the years indicated:
The following table summarizes key elements of each Employee Partnership as of December 31, 2020:
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:
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Hedging Activities and Fair Value Measurements (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments, Hedging Activities and Fair Value Measurements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Hedging Instruments Under the FASB's Derivative and Hedging Guidance |
The following table summarizes our portfolio of 30-year forward-starting swaps at December 31, 2020, all of which are associated with the expected future issuance of senior notes.
The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2020 (volume measures as noted):
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Derivative Assets and Liabilities Balance Sheet |
The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated:
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Offsetting Financial Assets |
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:
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Offsetting Financial Liabilities |
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Derivative Instruments Effects on Statements of Operations |
The following tables present the effect of our derivative instruments designated as fair value hedges on our Statements of Consolidated Operations for the years indicated:
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Derivative Instruments Effects on Statements of Comprehensive Income |
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:
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Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income |
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Gain/(Loss) Recognized in Income on Derivative |
The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the years indicated:
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Unrealized mark-to-market gains (losses) |
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 and interest expense for the years indicated:
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Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis |
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Reconciliation of Changes in the Fair Value of Level 3 Financial Assets and Liabilities |
The following table sets forth a reconciliation of changes in the fair values of our recurring Level 3 financial assets and liabilities on a combined basis for the years indicated:
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Nonrecurring Fair Value Measurements |
We wrote down the assets comprising our marine transportation business and certain natural gas gathering and processing activities to their estimated fair values in 2020 (see Note 4). Apart from these matters, we did not have any significant nonrecurring fair value measurements during the years ended December 31, 2020, 2019 or 2018. The following table presents information regarding our significant nonrecurring fair value measurements at December 31, 2020:
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Related Party Transactions (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions |
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:
At December 31, 2020, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us:
The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated:
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Income Taxes (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Federal and State Income Tax Provision |
The following table presents the components of our consolidated benefit from (provision for) income taxes for the years indicated:
Our federal, state and foreign income tax benefit (provision) is summarized below:
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Reconciliation of Provision for Income Taxes |
A reconciliation of the benefit from (provision for) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:
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Components of Deferred Tax Assets and Liabilities |
The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated:
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Commitments and Contingent Liabilities (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Contractual Obligations |
The following table summarizes our various contractual obligations at December 31, 2020. A description of each type of contractual obligation follows:
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Operating Leases |
The following table presents information regarding operating leases where we are the lessee at December 31, 2020:
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Consolidated Lease Expense |
In total, operating lease expense was $102.0 million, $106.6 million and $86.4 million for the years ended December 31, 2020, 2019 and 2018, respectively. The following table disaggregates our total operating lease expense for the years indicated:
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Schedule of Other Liabilities |
The following table summarizes the components of “Other long-term liabilities” as presented on our Consolidated Balance Sheets at the dates indicated:
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Supplemental Cash Flow Information (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Cash Flow Information [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Effect of Changes in Operating Assets and Liabilities |
The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the years indicated:
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Schedule of Significant Acquisitions and Disposals |
The following table presents our cash proceeds from asset sales for the years indicated:
The following table presents net gains attributable to asset sales for the years indicated:
|
Partnership Organization and Operations (Details) |
12 Months Ended |
---|---|
Dec. 31, 2020
Segment
| |
Related Party Transaction [Line Items] | |
Number of reportable segments | 4 |
EPCO and its privately held affiliates [Member] | Common Units [Member] | |
Related Party Transaction [Line Items] | |
Percentage of total units outstanding | 32.20% |
EPCO and its privately held affiliates [Member] | Preferred Units [Member] | |
Related Party Transaction [Line Items] | |
Percentage of total units outstanding | 30.20% |
Summary of Significant Accounting Policies, Part 2 (Details) |
12 Months Ended |
---|---|
Dec. 31, 2020 | |
Current Assets and Current Liabilities [Abstract] | |
Threshold for components of total current assets and current liabilities to be presented as an individual caption on Consolidated Balance Sheet | 5.00% |
Minimum [Member] | |
Derivative Instruments [Abstract] | |
Expected offset percentage of change in fair value derivative instrument | 80.00% |
Maximum [Member] | |
Derivative Instruments [Abstract] | |
Expected offset percentage of change in fair value derivative instrument | 125.00% |
Summary of Significant Accounting Policies, Part 3 (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||||||
Environmental Costs [Abstract] | |||||||||||
Environmental reserves - current portion | $ 3.8 | $ 5.8 | |||||||||
Asset Impairment Charges [Abstract] | |||||||||||
Impairment of property, plant and equipment | 589.8 | 51.1 | $ 46.8 | ||||||||
Impairment of goodwill | 296.3 | 0.0 | 0.0 | ||||||||
Impairment charges in operating costs and expenses | 890.6 | 132.7 | 50.5 | ||||||||
Total asset impairment charges | 890.6 | 132.8 | 50.5 | ||||||||
Lease Accounting Standard [Abstract] | |||||||||||
Right-of-use assets | [1] | 332.0 | |||||||||
Lease liabilities | [2] | 348.6 | |||||||||
Environmental Reserves [Member] | |||||||||||
Movement in valuation allowances and reserves [Roll Forward] | |||||||||||
Balance at beginning of period | 7.2 | 6.9 | 11.6 | ||||||||
Charged to costs and expenses | 6.2 | 12.3 | 8.2 | ||||||||
Acquisition-related additions and other | 2.6 | 2.5 | 1.7 | ||||||||
Deductions | (11.5) | (14.5) | (14.6) | ||||||||
Balance at end of period | 4.5 | 7.2 | 6.9 | ||||||||
Operating costs and expenses [Member] | |||||||||||
Asset Impairment Charges [Abstract] | |||||||||||
Impairment of property, plant and equipment | 589.8 | 51.0 | 46.8 | ||||||||
Impairment of investment in unconsolidated affiliate | 0.0 | 76.4 | 0.0 | ||||||||
Impairment of goodwill | 296.3 | 0.0 | 0.0 | ||||||||
Other impairments | [3] | 4.5 | 5.3 | 3.7 | |||||||
Impairment charges in operating costs and expenses | 890.6 | 132.7 | 50.5 | ||||||||
General and administrative costs [Member] | |||||||||||
Asset Impairment Charges [Abstract] | |||||||||||
Impairment of property, plant and equipment | [4] | $ 0.0 | $ 0.1 | 0.0 | |||||||
ASC 842 [Member] | |||||||||||
Lease Accounting Standard [Abstract] | |||||||||||
Right-of-use assets | 246.1 | ||||||||||
Lease liabilities | $ 246.1 | ||||||||||
|
Inventories (Details) - USD ($) $ in Millions |
12 Months Ended | ||||
---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||
Inventory by Product Type [Abstract] | |||||
NGLs | $ 1,888.1 | $ 1,094.9 | |||
Petrochemicals and refined products | 642.6 | 311.5 | |||
Crude oil | 758.1 | 674.2 | |||
Natural gas | 14.7 | 10.8 | |||
Total | 3,303.5 | 2,091.4 | |||
Summary of cost of sales and lower of cost or net realizable value adjustments [Abstract] | |||||
Cost of sales | [1] | 16,723.2 | 22,065.8 | $ 26,789.8 | |
Lower of cost or net realizable value adjustments recognized in cost of sales | $ 60.2 | $ 22.7 | $ 11.5 | ||
|
Property, Plant and Equipment (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Property, plant and equipment, gross | $ 57,497.5 | $ 55,285.0 | |||||||||||||||||
Less accumulated depreciation | 15,584.7 | 13,681.6 | |||||||||||||||||
Property, plant and equipment, net | 41,912.8 | 41,603.4 | $ 38,737.6 | ||||||||||||||||
Summary of depreciation expense and capitalized interest [Abstract] | |||||||||||||||||||
Depreciation expense | [1] | 1,681.9 | 1,562.6 | 1,436.2 | |||||||||||||||
Capitalized interest | [2] | 115.0 | 143.8 | 147.9 | |||||||||||||||
Asset Retirement Obligations [Roll Forward] | |||||||||||||||||||
ARO liability beginning balance | 132.1 | 126.3 | 86.7 | ||||||||||||||||
Liabilities incurred | 4.6 | 5.0 | 24.4 | ||||||||||||||||
Liabilities settled | (1.5) | (2.3) | (2.5) | ||||||||||||||||
Revisions in estimated cash flows | 6.1 | (4.8) | 11.5 | ||||||||||||||||
Accretion expense | 8.2 | 7.9 | 6.2 | ||||||||||||||||
ARO liability ending balance | 149.5 | 132.1 | $ 126.3 | ||||||||||||||||
Capitalized costs, asset retirement costs | 69.7 | 69.6 | |||||||||||||||||
Forecasted accretion expense [Abstract] | |||||||||||||||||||
2021 | 8.6 | ||||||||||||||||||
2022 | 9.1 | ||||||||||||||||||
2023 | 9.6 | ||||||||||||||||||
2024 | 10.3 | ||||||||||||||||||
2025 | 10.9 | ||||||||||||||||||
Plants, pipelines and facilities [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Property, plant and equipment, gross | [3] | $ 49,972.8 | 47,201.2 | ||||||||||||||||
Plants, pipelines and facilities [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | [3],[4] | 3 years | |||||||||||||||||
Plants, pipelines and facilities [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | [3],[4] | 45 years | |||||||||||||||||
Underground and other storage facilities [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Property, plant and equipment, gross | [5] | $ 4,207.5 | 3,965.5 | ||||||||||||||||
Underground and other storage facilities [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | [5],[6] | 5 years | |||||||||||||||||
Underground and other storage facilities [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | [5],[6] | 40 years | |||||||||||||||||
Transportation equipment [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Property, plant and equipment, gross | [7] | $ 204.9 | 198.9 | ||||||||||||||||
Transportation equipment [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | [7] | 3 years | |||||||||||||||||
Transportation equipment [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | [7] | 10 years | |||||||||||||||||
Marine vessels [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Property, plant and equipment, gross | [8] | $ 932.7 | 905.9 | ||||||||||||||||
Marine vessels [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | [8] | 15 years | |||||||||||||||||
Marine vessels [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | [8] | 30 years | |||||||||||||||||
Land [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Property, plant and equipment, gross | $ 371.9 | 372.3 | |||||||||||||||||
Construction in progress [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Property, plant and equipment, gross | $ 1,807.7 | $ 2,641.2 | |||||||||||||||||
Processing plants [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 20 years | ||||||||||||||||||
Processing plants [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 35 years | ||||||||||||||||||
Pipelines and related equipment [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 5 years | ||||||||||||||||||
Pipelines and related equipment [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 45 years | ||||||||||||||||||
Terminal facilities [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 10 years | ||||||||||||||||||
Terminal facilities [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 35 years | ||||||||||||||||||
Buildings [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 20 years | ||||||||||||||||||
Buildings [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 40 years | ||||||||||||||||||
Office furniture and equipment [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 3 years | ||||||||||||||||||
Office furniture and equipment [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 20 years | ||||||||||||||||||
Laboratory and shop equipment [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 5 years | ||||||||||||||||||
Laboratory and shop equipment [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 35 years | ||||||||||||||||||
Underground storage facilities [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 5 years | ||||||||||||||||||
Underground storage facilities [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 35 years | ||||||||||||||||||
Storage tanks [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 10 years | ||||||||||||||||||
Storage tanks [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 40 years | ||||||||||||||||||
Water wells [Member] | Minimum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 5 years | ||||||||||||||||||
Water wells [Member] | Maximum [Member] | |||||||||||||||||||
Property, plant and equipment and accumulated depreciation [Abstract] | |||||||||||||||||||
Estimated useful life | 35 years | ||||||||||||||||||
|
Property, Plant and Equipment, Impairments (Details) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020
USD ($)
Towboat
Tankbarges
|
Dec. 31, 2019
USD ($)
|
Dec. 31, 2018
USD ($)
|
|
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | $ 589.8 | $ 51.1 | $ 46.8 |
Total asset impairment charges | 890.6 | 132.8 | 50.5 |
Reclassification of construction in progress to other assets | 311.7 | ||
Midland-to-Echo 4 Pipeline [Member] | Crude Oil Pipelines & Services [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | 42.2 | ||
South Texas natural gas gathering and processing assets [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | 124.7 | ||
Impairment of intangible assets | 1.0 | ||
Total asset impairment charges | 125.7 | ||
Assets, fair value | 21.3 | ||
South Texas natural gas gathering and processing assets [Member] | NGL Pipelines & Services [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | 86.9 | 15.6 | |
South Texas natural gas gathering and processing assets [Member] | Natural Gas Pipelines & Services [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | 37.8 | ||
Marine transportation business [Member] | Petrochemical & Refined Products Services [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | 252.1 | ||
Impairment of intangible assets | 4.6 | ||
Total asset impairment charges | 256.7 | ||
Assets, fair value | $ 410.0 | ||
Number of tow boats | Towboat | 65 | ||
Number of tank barges | Tankbarges | 160 | ||
Other [Member] | NGL Pipelines & Services [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | $ 121.2 | 23.5 | 18.6 |
Other [Member] | Crude Oil Pipelines & Services [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | 3.3 | 2.6 | 11.2 |
Other [Member] | Natural Gas Pipelines & Services [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | 5.5 | 4.8 | 13.9 |
Other [Member] | Petrochemical & Refined Products Services [Member] | |||
Asset Impairment Charges [Abstract] | |||
Impairment of property, plant and equipment | $ 40.8 | $ 4.6 | $ 3.1 |
Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions |
12 Months Ended | ||||
---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||
Schedule of Equity Method Investments [Line Items] | |||||
Investments in unconsolidated affiliates | $ 2,429.2 | $ 2,600.2 | $ 2,615.1 | ||
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract] | |||||
Equity in income (loss) of unconsolidated affiliates | 426.1 | 563.0 | 480.0 | ||
NGL Pipelines & Services [Member] | |||||
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract] | |||||
Equity in income (loss) of unconsolidated affiliates | $ 121.3 | 114.5 | 117.0 | ||
NGL Pipelines & Services [Member] | Venice Energy Service Company, L.L.C. [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 13.10% | ||||
Investments in unconsolidated affiliates | $ 23.4 | 23.2 | |||
NGL Pipelines & Services [Member] | K/D/S Promix, L.L.C. [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Investments in unconsolidated affiliates | $ 23.0 | 25.7 | |||
NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 32.20% | ||||
Investments in unconsolidated affiliates | $ 13.8 | 15.6 | |||
NGL Pipelines & Services [Member] | Skelly-Belvieu Pipeline Company, L.L.C. [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Investments in unconsolidated affiliates | $ 31.6 | 33.1 | |||
NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 35.00% | ||||
Investments in unconsolidated affiliates | $ 342.8 | 358.1 | |||
NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 45.00% | ||||
Investments in unconsolidated affiliates | $ 37.7 | 41.1 | |||
NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 33.30% | ||||
Investments in unconsolidated affiliates | $ 199.3 | 207.0 | |||
Crude Oil Pipelines & Services [Member] | |||||
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract] | |||||
Equity in income (loss) of unconsolidated affiliates | $ 301.2 | 449.2 | 365.4 | ||
Crude Oil Pipelines & Services [Member] | Seaway Crude Holdings LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Investments in unconsolidated affiliates | $ 1,224.0 | 1,353.1 | |||
Crude Oil Pipelines & Services [Member] | Eagle Ford Pipeline LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Investments in unconsolidated affiliates | $ 376.8 | 386.5 | |||
Crude Oil Pipelines & Services [Member] | Eagle Ford Terminals Corpus Christi LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Investments in unconsolidated affiliates | $ 122.9 | 126.9 | |||
Natural Gas Pipelines & Services [Member] | |||||
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract] | |||||
Equity in income (loss) of unconsolidated affiliates | $ 5.8 | 6.3 | 6.8 | ||
Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Investments in unconsolidated affiliates | $ 18.2 | 19.1 | |||
Natural Gas Pipelines & Services [Member] | Old Ocean Pipeline, LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Investments in unconsolidated affiliates | $ 13.2 | 8.2 | |||
Petrochemical & Refined Products Services [Member] | |||||
Equity in income (loss) of unconsolidated affiliates by business segment [Abstract] | |||||
Equity in income (loss) of unconsolidated affiliates | [1] | $ (2.2) | (7.0) | $ (9.2) | |
Petrochemical & Refined Products Services [Member] | Centennial Pipeline LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Non-cash asset impairment charge of unconsolidated affiliate | 76.4 | ||||
Petrochemical & Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 30.00% | ||||
Investments in unconsolidated affiliates | $ 1.6 | 2.0 | |||
Petrochemical & Refined Products Services [Member] | Transport 4, LLC [Member] | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership interest | 25.00% | ||||
Investments in unconsolidated affiliates | $ 0.9 | $ 0.6 | |||
|
Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Identifiable intangible assets [Abstract] | |||
Gross Value | $ 5,135.8 | $ 5,136.5 | |
Accumulated Amortization | (1,826.7) | (1,687.5) | |
Carrying Value | 3,309.1 | 3,449.0 | $ 3,608.4 |
Amortization expense | 143.2 | 174.7 | 170.3 |
Forecasted amortization expense [Abstract] | |||
2021 | 144.5 | ||
2022 | 161.3 | ||
2023 | 169.0 | ||
2024 | 165.1 | ||
2025 | 163.5 | ||
Customer relationship intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Carrying Value | 3,080.0 | ||
Contract-based intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Carrying Value | 228.0 | ||
NGL Pipelines & Services [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 610.4 | 610.4 | |
Accumulated Amortization | (276.3) | (250.2) | |
Carrying Value | 334.1 | 360.2 | |
Amortization expense | 25.2 | 31.9 | 34.7 |
NGL Pipelines & Services [Member] | Customer relationship intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 447.8 | 447.8 | |
Accumulated Amortization | (221.3) | (206.3) | |
Carrying Value | 226.5 | 241.5 | |
NGL Pipelines & Services [Member] | Contract-based intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 162.6 | 162.6 | |
Accumulated Amortization | (55.0) | (43.9) | |
Carrying Value | 107.6 | 118.7 | |
Crude Oil Pipelines & Services [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 2,478.1 | 2,480.4 | |
Accumulated Amortization | (541.5) | (478.5) | |
Carrying Value | 1,936.6 | 2,001.9 | |
Amortization expense | 71.5 | 92.7 | 87.8 |
Crude Oil Pipelines & Services [Member] | Customer relationship intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 2,195.0 | 2,203.5 | |
Accumulated Amortization | (291.6) | (243.5) | |
Carrying Value | 1,903.4 | 1,960.0 | |
Crude Oil Pipelines & Services [Member] | Contract-based intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 283.1 | 276.9 | |
Accumulated Amortization | (249.9) | (235.0) | |
Carrying Value | 33.2 | 41.9 | |
Natural Gas Pipelines & Services [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 1,821.0 | 1,818.3 | |
Accumulated Amortization | (916.0) | (877.1) | |
Carrying Value | 905.0 | 941.2 | |
Amortization expense | 38.8 | 41.4 | 39.1 |
Natural Gas Pipelines & Services [Member] | Customer relationship intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 1,350.3 | 1,350.3 | |
Accumulated Amortization | (512.2) | (481.6) | |
Carrying Value | 838.1 | 868.7 | |
Natural Gas Pipelines & Services [Member] | Contract-based intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 470.7 | 468.0 | |
Accumulated Amortization | (403.8) | (395.5) | |
Carrying Value | 66.9 | 72.5 | |
Petrochemical & Refined Products Services [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 226.3 | 227.4 | |
Accumulated Amortization | (92.9) | (81.7) | |
Carrying Value | 133.4 | 145.7 | |
Amortization expense | 7.7 | 8.7 | $ 8.7 |
Petrochemical & Refined Products Services [Member] | Customer relationship intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 181.4 | 181.4 | |
Accumulated Amortization | (68.3) | (57.5) | |
Carrying Value | 113.1 | 123.9 | |
Petrochemical & Refined Products Services [Member] | Contract-based intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 44.9 | 46.0 | |
Accumulated Amortization | (24.6) | (24.2) | |
Carrying Value | $ 20.3 | $ 21.8 |
Intangible Assets and Goodwill, Significant Intangible Assets (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Identifiable intangible assets [Abstract] | |||
Gross Value | $ 5,135.8 | $ 5,136.5 | |
Accumulated Amortization | (1,826.7) | (1,687.5) | |
Carrying Value | 3,309.1 | $ 3,449.0 | $ 3,608.4 |
Customer relationship intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Carrying Value | 3,080.0 | ||
Impairment of customer relationship intangible assets | 5.6 | ||
Customer relationship intangibles [Member] | EFS Midstream [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 1,409.8 | ||
Accumulated Amortization | (188.1) | ||
Carrying Value | $ 1,221.7 | ||
Weighted Average Remaining Amortization Period | 21 years 4 months 24 days | ||
Customer relationship intangibles [Member] | State Line and Fairplay [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | $ 895.0 | ||
Accumulated Amortization | (224.0) | ||
Carrying Value | $ 671.0 | ||
Weighted Average Remaining Amortization Period | 26 years 2 months 12 days | ||
Customer relationship intangibles [Member] | San Juan Gathering [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | $ 331.3 | ||
Accumulated Amortization | (245.3) | ||
Carrying Value | $ 86.0 | ||
Weighted Average Remaining Amortization Period | 18 years 9 months 18 days | ||
Customer relationship intangibles [Member] | Oiltanking Partners L.P. [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | $ 1,192.5 | ||
Accumulated Amortization | (162.6) | ||
Carrying Value | $ 1,029.9 | ||
Weighted Average Remaining Amortization Period | 23 years | ||
Contract-based intangibles [Member] | |||
Identifiable intangible assets [Abstract] | |||
Carrying Value | $ 228.0 | ||
Contract-based intangibles [Member] | Oiltanking Partners L.P. [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | 293.3 | ||
Accumulated Amortization | (261.7) | ||
Carrying Value | $ 31.6 | ||
Weighted Average Remaining Amortization Period | 3 years | ||
Contract-based intangibles [Member] | Jonah Gas Gathering [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | $ 224.4 | ||
Accumulated Amortization | (175.8) | ||
Carrying Value | $ 48.6 | ||
Weighted Average Remaining Amortization Period | 21 years | ||
Contract-based intangibles [Member] | Delaware Basin Gas Processing LLC [Member] | |||
Identifiable intangible assets [Abstract] | |||
Gross Value | $ 82.6 | ||
Accumulated Amortization | (23.7) | ||
Carrying Value | $ 58.9 | ||
Weighted Average Remaining Amortization Period | 6 years |
Intangible Assets and Goodwill, Goodwill (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Changes in carrying amount of goodwill [Roll Forward] | |||
Balance at beginning of period | $ 5,745.2 | $ 5,745.2 | |
Impairment of goodwill | (296.3) | 0.0 | $ 0.0 |
Balance at end of period | 5,448.9 | 5,745.2 | 5,745.2 |
NGL Pipelines & Services [Member] | |||
Changes in carrying amount of goodwill [Roll Forward] | |||
Balance at beginning of period | 2,651.7 | 2,651.7 | |
Impairment of goodwill | 0.0 | ||
Balance at end of period | 2,651.7 | 2,651.7 | 2,651.7 |
Crude Oil Pipelines & Services [Member] | |||
Changes in carrying amount of goodwill [Roll Forward] | |||
Balance at beginning of period | 1,841.0 | 1,841.0 | |
Impairment of goodwill | 0.0 | ||
Balance at end of period | 1,841.0 | 1,841.0 | 1,841.0 |
Natural Gas Pipelines & Services [Member] | |||
Changes in carrying amount of goodwill [Roll Forward] | |||
Balance at beginning of period | 296.3 | 296.3 | |
Impairment of goodwill | (296.3) | ||
Balance at end of period | 0.0 | 296.3 | 296.3 |
Petrochemical & Refined Products Services [Member] | |||
Changes in carrying amount of goodwill [Roll Forward] | |||
Balance at beginning of period | 956.2 | 956.2 | |
Impairment of goodwill | 0.0 | ||
Balance at end of period | $ 956.2 | $ 956.2 | $ 956.2 |
Debt Obligations (Details) - USD ($) $ in Millions |
1 Months Ended | 12 Months Ended | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2021 |
Feb. 28, 2021 |
Aug. 31, 2020 |
Jan. 31, 2020 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 30,146.4 | $ 27,878.4 | |||||||||||||
Other, non-principal amounts | (280.7) | (253.3) | |||||||||||||
Less current maturities of debt | (1,325.0) | (1,981.9) | |||||||||||||
Total long-term debt | 28,540.7 | 25,643.2 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Repayment of debt obligations | 4,406.6 | 56,716.5 | $ 77,957.1 | ||||||||||||
Letters of credit outstanding for facilities and motor fuel tax obligations | 200.7 | ||||||||||||||
Senior Debt Obligations [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | 27,500.0 | 25,232.0 | |||||||||||||
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | 0.0 | 482.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Maximum borrowing capacity | $ 3,000.0 | ||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Weighted-average interest rate paid | 1.86% | ||||||||||||||
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Minimum [Member] | |||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Variable interest rates paid | 1.78% | ||||||||||||||
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Maximum [Member] | |||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Variable interest rates paid | 2.08% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes Q, due January 2020 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 0.0 | 500.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 5.25% | ||||||||||||||
Repayment of debt obligations | $ 500.0 | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes Y, due September 2020 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 0.0 | 1,000.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 5.20% | ||||||||||||||
Repayment of debt obligations | $ 1,000.0 | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes TT, due February 2021 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 750.0 | 750.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 2.80% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes TT, due February 2021 [Member] | Subsequent Event [Member] | |||||||||||||||
Debt Obligations Terms: | |||||||||||||||
Repayment of debt obligations | $ 750.0 | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes RR, due April 2021 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 575.0 | 575.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 2.85% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes RR, due April 2021 [Member] | Forecast [Member] | |||||||||||||||
Debt Obligations Terms: | |||||||||||||||
Repayment of debt obligations | $ 575.0 | ||||||||||||||
Senior Debt Obligations [Member] | September 2020 EPO 364-Day Revolving Credit Agreement, due September 2021 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 0.0 | 0.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Maximum borrowing capacity | 1,500.0 | ||||||||||||||
Maximum bank commitments increase | 200.0 | ||||||||||||||
Total maximum borrowing capacity | $ 1,700.0 | ||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Credit facility interest rate description | Amounts borrowed under EPO’s 364-Day and Multi-Year Revolving Credit Agreements bear interest, at its election, equal to: (i) LIBOR, plus an additional variable spread; or (ii) an alternate base rate, which is the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) the LIBO Market Index Rate in effect on such day plus 1% and a variable spread. The applicable spreads are determined based on EPO's debt ratings. | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes VV, due February 2022 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 750.0 | 750.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.50% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes CC, due February 2022 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 650.0 | 650.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.05% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes HH, due March 2023 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,250.0 | 1,250.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.35% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes JJ, due February 2024 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 850.0 | 850.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.90% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Multi-Year Revolving Credit Agreement, due September 2024 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 0.0 | 0.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Maximum borrowing capacity | 3,500.0 | ||||||||||||||
Maximum bank commitments increase | 500.0 | ||||||||||||||
Total maximum borrowing capacity | $ 4,000.0 | ||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Credit facility interest rate description | Amounts borrowed under EPO’s 364-Day and Multi-Year Revolving Credit Agreements bear interest, at its election, equal to: (i) LIBOR, plus an additional variable spread; or (ii) an alternate base rate, which is the greater of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) the LIBO Market Index Rate in effect on such day plus 1% and a variable spread. The applicable spreads are determined based on EPO's debt ratings. | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes MM, due February 2025 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,150.0 | 1,150.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.75% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes PP, due February 2026 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 875.0 | 875.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.70% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes SS, due February 2027[Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 575.0 | 575.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.95% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes WW, due October 2028 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,000.0 | 1,000.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.15% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes YY, due July 2029 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,250.0 | 1,250.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.125% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes AAA, due January 2030 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,250.0 | 0.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 2.80% | ||||||||||||||
Aggregate debt principal issued | $ 250.0 | $ 1,000.0 | |||||||||||||
Debt issued as percent of principal amount | 107.211% | 99.921% | |||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes D, due March 2033 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 500.0 | 500.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 6.875% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes H, due October 2034 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 350.0 | 350.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 6.65% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes J, due March 2035 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 250.0 | 250.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 5.75% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes W, due April 2038 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 399.6 | 399.6 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 7.55% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes R, due October 2039 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 600.0 | 600.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 6.125% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes Z, due September 2040 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 600.0 | 600.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 6.45% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes BB, due February 2041 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 750.0 | 750.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 5.95% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes DD, due February 2042 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 600.0 | 600.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 5.70% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes EE, due August 2042 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 750.0 | 750.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.85% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes GG, due February 2043 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,100.0 | 1,100.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.45% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes II, due March 2044 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,400.0 | 1,400.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.85% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes KK, due February 2045 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,150.0 | 1,150.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 5.10% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes QQ, due May 2046 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 975.0 | 975.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.90% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes UU, due February 2048 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,250.0 | 1,250.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.25% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes XX, due February 2049 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,250.0 | 1,250.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.80% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes ZZ, due January 2050 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,250.0 | 1,250.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.20% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes BBB, due January 2051 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,000.0 | 0.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.70% | ||||||||||||||
Aggregate debt principal issued | $ 1,000.0 | ||||||||||||||
Debt issued as percent of principal amount | 99.413% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes DDD, due February 2052 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,000.0 | 0.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.20% | ||||||||||||||
Aggregate debt principal issued | $ 1,000.0 | ||||||||||||||
Debt issued as percent of principal amount | 99.233% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes NN, due October 2054 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 400.0 | 400.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.95% | ||||||||||||||
Senior Debt Obligations [Member] | EPO Senior Notes CCC, due January 2060 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 1,000.0 | 0.0 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 3.95% | ||||||||||||||
Aggregate debt principal issued | $ 1,000.0 | ||||||||||||||
Debt issued as percent of principal amount | 99.36% | ||||||||||||||
Senior Debt Obligations [Member] | TEPPCO Senior Notes, due April 2038 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 0.4 | 0.4 | |||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 7.55% | ||||||||||||||
Junior Debt Obligations [Member] | |||||||||||||||
Debt Obligations Terms: | |||||||||||||||
Aggregate debt principal issued | 700.0 | ||||||||||||||
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | [1] | $ 232.2 | 232.2 | ||||||||||||
Debt Obligations Terms: | |||||||||||||||
Repayment of debt obligations | 24.2 | ||||||||||||||
Gain on extinguishment of debt | 1.5 | ||||||||||||||
Variable annual interest rate thereafter, variable rate basis | 3-month London Interbank Offered Rate ("LIBOR") | ||||||||||||||
Variable interest rate | [1] | 2.778% | |||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Weighted-average interest rate paid | 3.66% | ||||||||||||||
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member] | Minimum [Member] | |||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Variable interest rates paid | 3.00% | ||||||||||||||
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member] | Maximum [Member] | |||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Variable interest rates paid | 4.68% | ||||||||||||||
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D, due August 2077 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | [2] | $ 700.0 | 700.0 | ||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 4.875% | ||||||||||||||
Variable annual interest rate thereafter, variable rate basis | 3-month LIBOR | ||||||||||||||
Variable interest rate | 2.986% | ||||||||||||||
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes E, due August 2077 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | [3] | $ 1,000.0 | 1,000.0 | ||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 5.25% | ||||||||||||||
Variable annual interest rate thereafter, variable rate basis | 3-month LIBOR | ||||||||||||||
Variable interest rate | 3.033% | ||||||||||||||
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes F, due February 2078 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | [4] | $ 700.0 | 700.0 | ||||||||||||
Debt Obligations Terms: | |||||||||||||||
Interest rate, stated percentage | 5.375% | ||||||||||||||
Variable annual interest rate thereafter, variable rate basis | 3-month LIBOR | ||||||||||||||
Variable interest rate | 2.57% | ||||||||||||||
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | [1] | $ 14.2 | 14.2 | ||||||||||||
Debt Obligations Terms: | |||||||||||||||
Variable annual interest rate thereafter, variable rate basis | 3-month London Interbank Offered Rate ("LIBOR") | ||||||||||||||
Variable interest rate | 2.778% | ||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Weighted-average interest rate paid | 3.66% | ||||||||||||||
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | Minimum [Member] | |||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Variable interest rates paid | 3.00% | ||||||||||||||
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | Maximum [Member] | |||||||||||||||
Information regarding variable interest rates paid: | |||||||||||||||
Variable interest rates paid | 4.68% | ||||||||||||||
Senior Notes [Member] | |||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||
Principal outstanding | $ 27,500.0 | ||||||||||||||
Debt Obligations Terms: | |||||||||||||||
Aggregate debt principal issued | $ 3,000.0 | $ 4,250.0 | $ 2,500.0 | $ 5,000.0 | |||||||||||
|
Debt Obligations, Debt Maturities (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Scheduled Maturities of Debt [Abstract] | ||
2021 | $ 1,325.0 | |
2022 | 1,400.0 | |
2023 | 1,250.0 | |
2024 | 850.0 | |
2025 | 1,150.0 | |
Thereafter | 24,171.4 | |
Total | 30,146.4 | $ 27,878.4 |
Senior Notes [Member] | ||
Scheduled Maturities of Debt [Abstract] | ||
2021 | 1,325.0 | |
2022 | 1,400.0 | |
2023 | 1,250.0 | |
2024 | 850.0 | |
2025 | 1,150.0 | |
Thereafter | 21,525.0 | |
Total | 27,500.0 | |
Junior Subordinated Notes [Member] | ||
Scheduled Maturities of Debt [Abstract] | ||
2021 | 0.0 | |
2022 | 0.0 | |
2023 | 0.0 | |
2024 | 0.0 | |
2025 | 0.0 | |
Thereafter | 2,646.4 | |
Total | $ 2,646.4 |
Capital Accounts, Summary of Changes in Outstanding Units (Details) - Common Units [Member] - shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Summary of changes in outstanding units [Roll Forward] | |||
Number of common units outstanding, beginning balance (in units) | 2,189,226,130 | 2,184,869,029 | 2,161,089,479 |
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option in March 2020 (in units) | 54,807,352 | ||
Treasury units acquired in connection with settlement of Liquidity Option in March 2020 (in units) | (54,807,352) | ||
Common unit repurchases under buyback program (in units) | (8,978,317) | (2,909,128) | (1,236,800) |
Common units issued in connection with the vesting of phantom unit awards, net (in units) | 3,162,095 | 2,720,603 | 2,442,436 |
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled (in units) | (1,120,588) | ||
Common units issued in connection with DRIP and EUPP (in units) | 2,897,990 | 19,861,951 | |
Common units issued in connection with employee compensation (in units) | 1,626,041 | 1,443,586 | |
Common units issued in connection with land acquisition (in units) | 1,223,242 | ||
Other (in units) | 19,638 | 21,595 | 45,135 |
Number of common units outstanding, ending balance (in units) | 2,182,308,958 | 2,189,226,130 | 2,184,869,029 |
Capital Accounts, Issuances of Equity (Details) $ / shares in Units, $ in Millions |
12 Months Ended | ||||
---|---|---|---|---|---|
Dec. 31, 2020
USD ($)
Contract
shares
|
Dec. 31, 2019
USD ($)
shares
|
Dec. 31, 2018
USD ($)
shares
|
Mar. 05, 2020
$ / shares
|
Dec. 31, 2014 |
|
Net Cash Proceeds from Sale of Common Units [Abstract] | |||||
Net cash proceeds from the issuance of common units | $ 0.0 | $ 82.2 | $ 538.4 | ||
Common units issued in connection with employee compensation | 45.6 | 39.1 | |||
Liquidity Option Agreement [Abstract] | |||||
Limited partner interest of Oiltanking acquired | 65.90% | ||||
Percentage of capital stock we agreed to purchase under liquidity option agreement | 100.00% | ||||
Liquidity Option exercise period | 90 days | ||||
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option | $ 1,297.3 | ||||
Common units acquired in connection with buyback program | 186.3 | 81.1 | 30.8 | ||
Capital expenditures | $ 3,287.9 | $ 4,531.7 | 4,223.2 | ||
Land [Member] | |||||
Liquidity Option Agreement [Abstract] | |||||
Property, plant and equipment, additions | 85.2 | ||||
Capital expenditures | $ 55.2 | ||||
Common units issued in connection with land acquisition (in units) | shares | 1,223,242 | ||||
Phantom Unit Awards [Member] | |||||
Liquidity Option Agreement [Abstract] | |||||
Common units issued in connection with the vesting of phantom unit awards, net (in units) | shares | 3,162,095 | 2,720,603 | 2,442,436 | ||
Enterprise Products Partners L.P. [Member] | |||||
Liquidity Option Agreement [Abstract] | |||||
Closing price (in dollars per unit) | $ / shares | $ 23.67 | ||||
2019 Buyback Program [Member] | |||||
Liquidity Option Agreement [Abstract] | |||||
Total of common units repurchased under a buyback program (in units) | shares | 8,978,317 | 2,909,128 | |||
Common units acquired in connection with buyback program | $ 186.3 | $ 81.1 | |||
Amount authorized under 2019 Buyback Program | 2,000.0 | ||||
Remaining available capacity under the 2019 Buyback Program | 1,730.0 | ||||
Legacy Buyback Program [Member] | |||||
Liquidity Option Agreement [Abstract] | |||||
Maximum common units authorized for repurchase under a buyback program (in units) | shares | 4,000,000 | ||||
Total of common units repurchased under a buyback program (in units) | shares | 1,236,800 | ||||
Common units acquired in connection with buyback program | $ 30.8 | ||||
Long-Term Incentive Plan (2008) [Member] | |||||
Net Cash Proceeds from Sale of Common Units [Abstract] | |||||
Common units issued in connection with employee compensation (in units) | shares | 1,626,041 | 1,443,586 | |||
Universal Shelf Registration [Member] | Senior Debt Obligations [Member] | |||||
Net Cash Proceeds from Sale of Common Units [Abstract] | |||||
Debt issued under universal shelf registration | 4,250.0 | ||||
At-the-Market Registration [Member] | |||||
Registration Statements and Equity Offerings [Line Items] | |||||
Maximum common units authorized for issuance | 2,540.0 | ||||
Net Cash Proceeds from Sale of Common Units [Abstract] | |||||
Remaining units available for issuance | 2,540.0 | ||||
Skyline Registration Rights Agreement [Member] | |||||
Registration Statements and Equity Offerings [Line Items] | |||||
Maximum common units authorized for issuance | $ 500.0 | ||||
Liquidity Option Agreement [Abstract] | |||||
Number of registration statements following exercise of Liquidity Option | Contract | 5 | ||||
Distribution Reinvestment Plan [Member] | |||||
Net Cash Proceeds from Sale of Common Units [Abstract] | |||||
Remaining units available for issuance (in units) | shares | 50,615,246 | ||||
Distribution Reinvestment Plan [Member] | EPCO and its privately held affiliates [Member] | |||||
Net Cash Proceeds from Sale of Common Units [Abstract] | |||||
Gross proceeds from the sale of common units | $ 29.0 | $ 213.0 | |||
Employee Unit Purchase Plan [Member] | |||||
Net Cash Proceeds from Sale of Common Units [Abstract] | |||||
Employer contribution to EUPP | $ 2.4 | $ 0.9 | |||
Remaining units available for issuance (in units) | shares | 3,318,607 | ||||
Distribution Reinvestment and Employee Unit Purchase Plans [Member] | |||||
Net Cash Proceeds from Sale of Common Units [Abstract] | |||||
Number of common units issued (in units) | shares | 2,897,990 | 19,861,951 | |||
Number of common units purchased on the open market and delivered to participants (in units) | shares | 6,982,963 | 2,801,196 | |||
Net cash proceeds from the issuance of common units | $ 82.2 | $ 538.4 |
Capital Accounts, Redeemable Preferred Limited Partner Interests (Details) - USD ($) $ / shares in Units, $ in Millions |
1 Months Ended | 3 Months Ended | 12 Months Ended | ||
---|---|---|---|---|---|
Sep. 30, 2020 |
Dec. 31, 2020 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Temporary Equity [Line Items] | |||||
Treasury units | $ 1,297.3 | $ 1,297.3 | $ 0.0 | ||
Series A cumulative convertible preferred units (in dollars per unit) | $ 1,000 | $ 1,000 | |||
Series A cumulative convertible preferred units issued (in units) | 35,000 | ||||
Series A cumulative convertible preferred units outstanding (in units) | 50,000 | 50,138 | 50,138 | ||
Cash proceeds from the issuance of preferred units | $ 32.5 | $ 31.5 | $ 0.0 | $ 0.0 | |
Common units exchanged for preferred units, with common units received being immediately cancelled | 17.5 | 17.5 | |||
Total offering price for redeemable noncontrolling interests | $ 50.0 | ||||
Offering expenses | 1.0 | ||||
Total distributions paid to convertible preferred unitholders | 0.5 | ||||
Cash distributions paid to convertible preferred unitholders | $ 0.3 | ||||
Preferred unit distribution rate | 7.25% | ||||
Redemption price per preferred unit after September 30, 2025 at unitholder election (in dollars per unit) | $ 1,000 | ||||
Redemption price per preferred unit from September 30, 2020 through September 29, 2022 (in dollars per unit) | 1,100 | ||||
Redemption price per preferred unit from September 30, 2022 through September 29, 2024 (in dollars per unit) | 1,070 | ||||
Redemption price per preferred unit from September 30, 2024 through September 29, 2025 (in dollars per unit) | 1,030 | ||||
Redemption price per preferred unit from September 30, 2025 through September 29, 2026 (in dollars per unit) | 1,010 | ||||
Redemption price per preferred unit on or after September 30, 2026 (in dollars per unit) | 1,000 | ||||
Redemption price per preferred unit if Change of Control event occurs (in dollars per unit) | $ 1,010 | ||||
Percentage applied to the common unit market price in calculating the number of common units to be acquired upon the conversion of series A preferred units to common units | 92.50% | ||||
Percentage of preferred units that may be converted into common units at unitholder option | 50.00% | ||||
EPCO and its privately held affiliates [Member] | |||||
Temporary Equity [Line Items] | |||||
Series A cumulative convertible preferred units issued (in units) | 15,000 | ||||
Series A cumulative convertible preferred units, paid-in kind distribution (in units) | 138 | ||||
Cash proceeds from the issuance of preferred units | $ 15.0 | ||||
Preferred Units [Member] | |||||
Temporary Equity [Line Items] | |||||
Treasury units outstanding (preferred units) (in units) | 855,915 | ||||
Common Units [Member] | |||||
Temporary Equity [Line Items] | |||||
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled (in units) | 1,120,588 |
Capital Accounts, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Accumulated Other Comprehensive Income (Loss) [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Beginning Balance | $ 71.4 | $ 50.9 | |
Other comprehensive income (loss) for period, before reclassifications | (3.2) | 124.9 | |
Reclassification of losses (gains) to net income during period | (233.4) | (104.4) | |
Total other comprehensive income (loss) for period | (236.6) | 20.5 | $ 222.6 |
Accumulated Other Comprehensive Income (Loss), Ending balance | (165.2) | 71.4 | 50.9 |
Interest expense | 1,287.4 | 1,243.0 | 1,096.7 |
Revenue | (27,199.7) | (32,789.2) | (36,534.2) |
Operating costs and expenses | 22,371.1 | 27,061.8 | 31,397.3 |
Total | (3,885.7) | (4,687.1) | (4,238.5) |
Cash Flow Hedges [Member] | Commodity Derivatives [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Beginning Balance | 55.1 | 152.7 | |
Other comprehensive income (loss) for period, before reclassifications | 124.4 | 44.1 | |
Reclassification of losses (gains) to net income during period | (272.7) | (141.7) | |
Total other comprehensive income (loss) for period | (148.3) | (97.6) | |
Accumulated Other Comprehensive Income (Loss), Ending balance | (93.2) | 55.1 | 152.7 |
Cash Flow Hedges [Member] | Interest Rate Derivatives [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Beginning Balance | 13.9 | (104.8) | |
Other comprehensive income (loss) for period, before reclassifications | (127.5) | 81.4 | |
Reclassification of losses (gains) to net income during period | 39.3 | 37.3 | |
Total other comprehensive income (loss) for period | (88.2) | 118.7 | |
Accumulated Other Comprehensive Income (Loss), Ending balance | (74.3) | 13.9 | (104.8) |
Other [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Beginning Balance | 2.4 | 3.0 | |
Other comprehensive income (loss) for period, before reclassifications | (0.1) | (0.6) | |
Reclassification of losses (gains) to net income during period | 0.0 | 0.0 | |
Total other comprehensive income (loss) for period | (0.1) | (0.6) | |
Accumulated Other Comprehensive Income (Loss), Ending balance | 2.3 | 2.4 | $ 3.0 |
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Abstract] | |||
Total | (233.4) | (104.4) | |
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Commodity Derivatives [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Abstract] | |||
Revenue | (282.6) | (152.4) | |
Operating costs and expenses | 9.9 | 10.7 | |
Reclassification out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Interest Rate Derivatives [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Abstract] | |||
Interest expense | $ 39.3 | $ 37.3 |
Capital Accounts, Noncontrolling Interests (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||||||
Noncontrolling Interest | |||||||||||
Noncontrolling interests | $ 1,073.3 | $ 1,063.5 | |||||||||
Net income attributable to noncontrolling interests | 110.1 | 95.8 | $ 66.1 | ||||||||
Breviloba LLC [Member] | |||||||||||
Noncontrolling Interest | |||||||||||
Noncontrolling Interest, Increase from Sale of Parent Equity Interest | 440.7 | ||||||||||
Noncontrolling interests | [1] | 480.4 | 492.9 | ||||||||
Whitehorn Pipeline Company LLC [Member] | |||||||||||
Noncontrolling Interest | |||||||||||
Noncontrolling Interest, Increase from Sale of Parent Equity Interest | $ 189.6 | ||||||||||
Noncontrolling interests | [2] | 193.0 | 198.9 | ||||||||
Enterprise Navigator Ethylene Terminal LLC [Member] | |||||||||||
Noncontrolling Interest | |||||||||||
Noncontrolling interests | [3] | 142.2 | 124.3 | ||||||||
Other [Member] | |||||||||||
Noncontrolling Interest | |||||||||||
Noncontrolling interests | [4] | $ 257.7 | $ 247.4 | ||||||||
Altus Midstream Processing LP [Member] | Breviloba LLC [Member] | |||||||||||
Noncontrolling Interest | |||||||||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 33.00% | ||||||||||
Western Gas Partners, LP [Member] | Whitehorn Pipeline Company LLC [Member] | |||||||||||
Noncontrolling Interest | |||||||||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 20.00% | ||||||||||
Navigator Ethylene Terminals LLC [Member] | Enterprise Navigator Ethylene Terminal LLC [Member] | |||||||||||
Noncontrolling Interest | |||||||||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 50.00% | ||||||||||
|
Capital Accounts, Distributions (Details) - USD ($) $ / shares in Units, $ in Millions |
1 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Feb. 28, 2021 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Distributions to Partners [Abstract] | ||||
Number of days after quarter end to distribute available cash | 45 days | |||
Cash payments made in connection with distribution equivalent rights | $ 27.1 | $ 22.1 | $ 17.7 | |
Subsequent Event [Member] | ||||
Distributions to Partners [Abstract] | ||||
Cash distributions paid | $ 988.8 | |||
Cash payments made in connection with distribution equivalent rights | $ 7.1 | |||
Cash Distribution [Member] | First Quarter 2018 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4275 | |||
Record Date | Apr. 30, 2018 | |||
Payment Date | May 08, 2018 | |||
Cash Distribution [Member] | Second Quarter 2018 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4300 | |||
Record Date | Jul. 31, 2018 | |||
Payment Date | Aug. 08, 2018 | |||
Cash Distribution [Member] | Third Quarter 2018 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4325 | |||
Record Date | Oct. 31, 2018 | |||
Payment Date | Nov. 08, 2018 | |||
Cash Distribution [Member] | Fourth Quarter 2018 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4350 | |||
Record Date | Jan. 31, 2019 | |||
Payment Date | Feb. 08, 2019 | |||
Cash Distribution [Member] | First Quarter 2019 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4375 | |||
Record Date | Apr. 30, 2019 | |||
Payment Date | May 13, 2019 | |||
Cash Distribution [Member] | Second Quarter 2019 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4400 | |||
Record Date | Jul. 31, 2019 | |||
Payment Date | Aug. 13, 2019 | |||
Cash Distribution [Member] | Third Quarter 2019 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4425 | |||
Record Date | Oct. 31, 2019 | |||
Payment Date | Nov. 12, 2019 | |||
Cash Distribution [Member] | Fourth Quarter 2019 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4450 | |||
Record Date | Jan. 31, 2020 | |||
Payment Date | Feb. 12, 2020 | |||
Cash Distribution [Member] | First Quarter 2020 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4450 | |||
Record Date | Apr. 30, 2020 | |||
Payment Date | May 12, 2020 | |||
Cash Distribution [Member] | Second Quarter 2020 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4450 | |||
Record Date | Jul. 31, 2020 | |||
Payment Date | Aug. 12, 2020 | |||
Cash Distribution [Member] | Third Quarter 2020 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4450 | |||
Record Date | Oct. 30, 2020 | |||
Payment Date | Nov. 12, 2020 | |||
Cash Distribution [Member] | Fourth Quarter 2020 Distribution [Member] | ||||
Distributions to Partners [Abstract] | ||||
Distribution Per Common Unit (in dollars per unit) | $ 0.4500 | |||
Record Date | Jan. 29, 2021 | |||
Payment Date | Feb. 11, 2021 |
Revenues, Revenues by Business Segment and Revenue Type (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Revenue [Abstract] | |||
Revenues | $ 27,199.7 | $ 32,789.2 | $ 36,534.2 |
NGL Pipelines & Services [Member] | |||
Revenue [Abstract] | |||
Revenues | 11,177.2 | 13,470.7 | 15,648.9 |
NGL Pipelines & Services [Member] | Sales of NGLs and Related Products [Member] | |||
Revenue [Abstract] | |||
Revenues | 8,970.7 | 10,934.3 | 12,920.9 |
NGL Pipelines & Services [Member] | Midstream Services [Member] | |||
Revenue [Abstract] | |||
Revenues | 2,206.5 | 2,536.4 | 2,728.0 |
NGL Pipelines & Services [Member] | Midstream Services: Natural Gas Processing and Fractionation [Member] | |||
Revenue [Abstract] | |||
Revenues | 757.3 | 1,069.9 | 1,341.0 |
NGL Pipelines & Services [Member] | Midstream Services: Transportation [Member] | |||
Revenue [Abstract] | |||
Revenues | 1,036.8 | 1,054.3 | 1,007.0 |
NGL Pipelines & Services [Member] | Midstream Services: Storage and Terminals [Member] | |||
Revenue [Abstract] | |||
Revenues | 412.4 | 412.2 | 380.0 |
Crude Oil Pipelines & Services [Member] | |||
Revenue [Abstract] | |||
Revenues | 6,689.0 | 10,287.3 | 11,042.6 |
Crude Oil Pipelines & Services [Member] | Sales of Crude Oil [Member] | |||
Revenue [Abstract] | |||
Revenues | 5,410.8 | 9,007.8 | 10,001.2 |
Crude Oil Pipelines & Services [Member] | Midstream Services [Member] | |||
Revenue [Abstract] | |||
Revenues | 1,278.2 | 1,279.5 | 1,041.4 |
Crude Oil Pipelines & Services [Member] | Midstream Services: Transportation [Member] | |||
Revenue [Abstract] | |||
Revenues | 804.9 | 801.8 | 676.5 |
Crude Oil Pipelines & Services [Member] | Midstream Services: Storage and Terminals [Member] | |||
Revenue [Abstract] | |||
Revenues | 473.3 | 477.7 | 364.9 |
Natural Gas Pipelines & Services [Member] | |||
Revenue [Abstract] | |||
Revenues | 2,553.1 | 3,169.4 | 3,454.4 |
Natural Gas Pipelines & Services [Member] | Sales of Natural Gas [Member] | |||
Revenue [Abstract] | |||
Revenues | 1,530.5 | 2,075.4 | 2,411.7 |
Natural Gas Pipelines & Services [Member] | Midstream Services [Member] | |||
Revenue [Abstract] | |||
Revenues | 1,022.6 | 1,094.0 | 1,042.7 |
Natural Gas Pipelines & Services [Member] | Midstream Services: Transportation [Member] | |||
Revenue [Abstract] | |||
Revenues | 1,022.6 | 1,094.0 | 1,042.7 |
Petrochemical & Refined Products Services [Member] | |||
Revenue [Abstract] | |||
Revenues | 6,780.4 | 5,861.8 | 6,388.3 |
Petrochemical & Refined Products Services [Member] | Sales of Petrochemicals and Refined Products [Member] | |||
Revenue [Abstract] | |||
Revenues | 5,942.6 | 4,985.2 | 5,535.4 |
Petrochemical & Refined Products Services [Member] | Midstream Services [Member] | |||
Revenue [Abstract] | |||
Revenues | 837.8 | 876.6 | 852.9 |
Petrochemical & Refined Products Services [Member] | Midstream Services: Fractionation and Isomerization [Member] | |||
Revenue [Abstract] | |||
Revenues | 187.7 | 166.6 | 188.3 |
Petrochemical & Refined Products Services [Member] | Midstream Services: Transportation [Member] | |||
Revenue [Abstract] | |||
Revenues | 482.9 | 539.4 | 481.8 |
Petrochemical & Refined Products Services [Member] | Midstream Services: Storage and Terminals [Member] | |||
Revenue [Abstract] | |||
Revenues | $ 167.2 | $ 170.6 | $ 182.8 |
Revenues, Unbilled Revenue and Deferred Revenue (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|---|---|
Contracts with Customers, Assets and Liabilities [Abstract] | ||||
Unbilled revenue | $ 18.8 | $ 17.6 | $ 13.3 | $ 0.0 |
Deferred revenue | 343.5 | 314.9 | $ 291.2 | $ 224.7 |
Other Current Assets [Member] | ||||
Contracts with Customers, Assets and Liabilities [Abstract] | ||||
Unbilled revenue (current amount) | 18.8 | 17.6 | ||
Other Current Liabilities [Member] | ||||
Contracts with Customers, Assets and Liabilities [Abstract] | ||||
Deferred revenue (current amount) | 145.3 | 117.9 | ||
Other Liabilities [Member] | ||||
Contracts with Customers, Assets and Liabilities [Abstract] | ||||
Deferred revenue (noncurrent) | $ 198.2 | $ 197.0 |
Revenues, Significant Changes in Unbilled Revenue (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||
Significant Changes in Unbilled Revenue | |||||||
Balance at beginning of period | $ 17.6 | $ 13.3 | $ 0.0 | ||||
Unbilled revenue included in opening balance transferred to other accounts during period | [1] | (17.6) | (13.3) | 0.0 | |||
Unbilled revenue recorded during period | [2] | 323.0 | 340.0 | 321.7 | |||
Unbilled revenue recorded during period transferred to other accounts | [1] | (304.2) | (322.4) | (310.6) | |||
Unbilled revenue recorded in connection with business combination | 2.2 | ||||||
Other changes | 0.0 | 0.0 | 0.0 | ||||
Balance at end of period | $ 18.8 | $ 17.6 | $ 13.3 | ||||
|
Revenues, Significant Changes in Deferred Revenue (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||
Significant Changes in Deferred Revenue | |||||||
Balance at beginning of period | $ 314.9 | $ 291.2 | $ 224.7 | ||||
Deferred revenue included in opening balance transferred to other accounts during period | [1] | (114.5) | (126.4) | (90.8) | |||
Deferred revenue recorded during period | [2] | 661.2 | 539.8 | 432.5 | |||
Deferred revenue recorded during period transferred to other accounts | [1] | (496.7) | (384.8) | (274.8) | |||
Deferred revenue recorded in connection with business combination | 0.0 | ||||||
Other changes | (21.4) | (4.9) | (0.4) | ||||
Balance at end of period | $ 343.5 | $ 314.9 | $ 291.2 | ||||
|
Revenues, Remaining Performance Obligations (Details) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Remaining Performance Obligation to be Recognized in the Future [Abstract] | |
Remaining performance obligation | $ 28,995.2 |
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | |
Remaining Performance Obligation to be Recognized in the Future [Abstract] | |
Remaining performance obligation | $ 3,906.4 |
Expected timing of satisfaction, period | 1 year |
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Remaining Performance Obligation to be Recognized in the Future [Abstract] | |
Remaining performance obligation | $ 3,492.3 |
Expected timing of satisfaction, period | 1 year |
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |
Remaining Performance Obligation to be Recognized in the Future [Abstract] | |
Remaining performance obligation | $ 3,110.2 |
Expected timing of satisfaction, period | 1 year |
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |
Remaining Performance Obligation to be Recognized in the Future [Abstract] | |
Remaining performance obligation | $ 2,937.3 |
Expected timing of satisfaction, period | 1 year |
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |
Remaining Performance Obligation to be Recognized in the Future [Abstract] | |
Remaining performance obligation | $ 2,636.5 |
Expected timing of satisfaction, period | 1 year |
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | |
Remaining Performance Obligation to be Recognized in the Future [Abstract] | |
Remaining performance obligation | $ 12,912.5 |
Expected timing of satisfaction, period |
Business Segments (Details) |
12 Months Ended |
---|---|
Dec. 31, 2020
Segment
| |
Segment Reporting Information [Line Items] | |
Number of reportable segments | 4 |
Business Segments, Gross Operating Margin (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||
Business Segments [Abstract] | |||||||
Operating income | $ 5,035.1 | $ 6,078.7 | $ 5,408.6 | ||||
Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign): | |||||||
Depreciation, amortization and accretion expense in operating costs and expenses | 1,961.5 | 1,848.3 | 1,687.0 | ||||
Asset impairment and related charges in operating costs and expenses | 890.6 | 132.7 | 50.5 | ||||
Net gains attributable to asset sales in operating costs and expenses | (4.4) | (5.7) | (28.7) | ||||
General and administrative costs | 219.6 | 211.7 | 208.3 | ||||
Non-refundable payments received from shippers attributable to make-up rights | [1] | 119.3 | 47.0 | 21.5 | |||
Subsequent recognition of revenues attributable to make-up rights | [2] | (33.6) | (22.9) | (56.2) | |||
Total segment gross operating margin | $ 8,188.1 | $ 8,289.8 | $ 7,291.0 | ||||
|
Business Segments, Segment Reporting Information (Details) - USD ($) $ in Millions |
12 Months Ended | ||||
---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||
Information by business segment [Abstract] | |||||
Gross operating margin | $ 8,188.1 | $ 8,289.8 | $ 7,291.0 | ||
Revenues from third parties | 27,163.0 | 32,721.9 | 36,426.5 | ||
Revenues from related parties | 36.7 | 67.3 | 107.7 | ||
Intersegment and intrasegment revenues | 0.0 | 0.0 | 0.0 | ||
Total revenues | 27,199.7 | 32,789.2 | 36,534.2 | ||
Equity in income (loss) of unconsolidated affiliates | 426.1 | 563.0 | 480.0 | ||
Property, plant and equipment, net | 41,912.8 | 41,603.4 | 38,737.6 | ||
Investments in unconsolidated affiliates | 2,429.2 | 2,600.2 | 2,615.1 | ||
Intangible assets, net | 3,309.1 | 3,449.0 | 3,608.4 | ||
Goodwill | 5,448.9 | 5,745.2 | 5,745.2 | ||
Segment assets | 53,100.0 | 53,397.8 | 50,706.3 | ||
NGL Pipelines and Services [Member] | |||||
Information by business segment [Abstract] | |||||
Total revenues | 11,177.2 | 13,470.7 | 15,648.9 | ||
Equity in income (loss) of unconsolidated affiliates | 121.3 | 114.5 | 117.0 | ||
Intangible assets, net | 334.1 | 360.2 | |||
Goodwill | 2,651.7 | 2,651.7 | 2,651.7 | ||
Crude Oil Pipelines & Services [Member] | |||||
Information by business segment [Abstract] | |||||
Total revenues | 6,689.0 | 10,287.3 | 11,042.6 | ||
Equity in income (loss) of unconsolidated affiliates | 301.2 | 449.2 | 365.4 | ||
Intangible assets, net | 1,936.6 | 2,001.9 | |||
Goodwill | 1,841.0 | 1,841.0 | 1,841.0 | ||
Natural Gas Pipelines & Services [Member] | |||||
Information by business segment [Abstract] | |||||
Total revenues | 2,553.1 | 3,169.4 | 3,454.4 | ||
Equity in income (loss) of unconsolidated affiliates | 5.8 | 6.3 | 6.8 | ||
Intangible assets, net | 905.0 | 941.2 | |||
Goodwill | 0.0 | 296.3 | 296.3 | ||
Petrochemical & Refined Products Services [Member] | |||||
Information by business segment [Abstract] | |||||
Total revenues | 6,780.4 | 5,861.8 | 6,388.3 | ||
Equity in income (loss) of unconsolidated affiliates | [1] | (2.2) | (7.0) | (9.2) | |
Intangible assets, net | 133.4 | 145.7 | |||
Goodwill | 956.2 | 956.2 | 956.2 | ||
Reportable Business Segments [Member] | NGL Pipelines and Services [Member] | |||||
Information by business segment [Abstract] | |||||
Gross operating margin | 4,182.4 | 4,069.8 | 3,830.7 | ||
Revenues from third parties | 11,170.6 | 13,460.8 | 15,630.5 | ||
Revenues from related parties | 6.6 | 9.9 | 18.4 | ||
Intersegment and intrasegment revenues | 29,010.3 | 20,840.4 | 26,453.6 | ||
Total revenues | 40,187.5 | 34,311.1 | 42,102.5 | ||
Equity in income (loss) of unconsolidated affiliates | 121.3 | 114.5 | 117.0 | ||
Property, plant and equipment, net | 17,128.3 | 16,652.1 | 14,845.4 | ||
Investments in unconsolidated affiliates | 671.6 | 703.8 | 662.0 | ||
Intangible assets, net | 334.1 | 360.2 | 380.1 | ||
Goodwill | 2,651.7 | 2,651.7 | 2,651.7 | ||
Segment assets | 20,785.7 | 20,367.8 | 18,539.2 | ||
Reportable Business Segments [Member] | Crude Oil Pipelines & Services [Member] | |||||
Information by business segment [Abstract] | |||||
Gross operating margin | 1,997.3 | 2,087.8 | 1,511.3 | ||
Revenues from third parties | 6,668.8 | 10,244.6 | 10,968.2 | ||
Revenues from related parties | 20.2 | 42.7 | 74.4 | ||
Intersegment and intrasegment revenues | 24,531.3 | 34,613.0 | 35,490.4 | ||
Total revenues | 31,220.3 | 44,900.3 | 46,533.0 | ||
Equity in income (loss) of unconsolidated affiliates | 301.2 | 449.2 | 365.4 | ||
Property, plant and equipment, net | 6,982.6 | 6,324.4 | 5,847.7 | ||
Investments in unconsolidated affiliates | 1,723.7 | 1,866.5 | 1,867.5 | ||
Intangible assets, net | 1,936.6 | 2,001.9 | 2,094.6 | ||
Goodwill | 1,841.0 | 1,841.0 | 1,841.0 | ||
Segment assets | 12,483.9 | 12,033.8 | 11,650.8 | ||
Reportable Business Segments [Member] | Natural Gas Pipelines & Services [Member] | |||||
Information by business segment [Abstract] | |||||
Gross operating margin | 926.6 | 1,062.6 | 891.2 | ||
Revenues from third parties | 2,543.2 | 3,154.7 | 3,439.5 | ||
Revenues from related parties | 9.9 | 14.7 | 14.9 | ||
Intersegment and intrasegment revenues | 460.1 | 624.7 | 721.9 | ||
Total revenues | 3,013.2 | 3,794.1 | 4,176.3 | ||
Equity in income (loss) of unconsolidated affiliates | 5.8 | 6.3 | 6.8 | ||
Property, plant and equipment, net | 8,465.8 | 8,432.5 | 8,303.8 | ||
Investments in unconsolidated affiliates | 31.4 | 27.3 | 22.8 | ||
Intangible assets, net | 905.0 | 941.2 | 979.3 | ||
Goodwill | 0.0 | 296.3 | 296.3 | ||
Segment assets | 9,402.2 | 9,697.3 | 9,602.2 | ||
Reportable Business Segments [Member] | Petrochemical & Refined Products Services [Member] | |||||
Information by business segment [Abstract] | |||||
Gross operating margin | 1,081.8 | 1,069.6 | 1,057.8 | ||
Revenues from third parties | 6,780.4 | 5,861.8 | 6,388.3 | ||
Revenues from related parties | 0.0 | 0.0 | 0.0 | ||
Intersegment and intrasegment revenues | 5,379.4 | 2,481.3 | 2,917.5 | ||
Total revenues | 12,159.8 | 8,343.1 | 9,305.8 | ||
Equity in income (loss) of unconsolidated affiliates | (2.2) | (7.0) | (9.2) | ||
Property, plant and equipment, net | 7,528.4 | 7,553.2 | 6,213.9 | ||
Investments in unconsolidated affiliates | 2.5 | 2.6 | 62.8 | ||
Intangible assets, net | 133.4 | 145.7 | 154.4 | ||
Goodwill | 956.2 | 956.2 | 956.2 | ||
Segment assets | 8,620.5 | 8,657.7 | 7,387.3 | ||
Eliminations [Member] | |||||
Information by business segment [Abstract] | |||||
Revenues from third parties | 0.0 | 0.0 | 0.0 | ||
Revenues from related parties | 0.0 | 0.0 | 0.0 | ||
Intersegment and intrasegment revenues | (59,381.1) | (58,559.4) | (65,583.4) | ||
Total revenues | (59,381.1) | (58,559.4) | (65,583.4) | ||
Equity in income (loss) of unconsolidated affiliates | 0.0 | 0.0 | 0.0 | ||
Adjustments [Member] | |||||
Information by business segment [Abstract] | |||||
Property, plant and equipment, net | 1,807.7 | 2,641.2 | 3,526.8 | ||
Investments in unconsolidated affiliates | 0.0 | 0.0 | 0.0 | ||
Intangible assets, net | 0.0 | 0.0 | 0.0 | ||
Goodwill | 0.0 | 0.0 | 0.0 | ||
Segment assets | $ 1,807.7 | $ 2,641.2 | $ 3,526.8 | ||
|
Business Segments, Consolidated Revenues and Expenses (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | $ 27,199.7 | $ 32,789.2 | $ 36,534.2 | ||||
Operating costs and expenses: | |||||||
Cost of sales | [1] | 16,723.2 | 22,065.8 | 26,789.8 | |||
Other operating costs and expenses | [2] | 2,800.2 | 3,020.7 | 2,898.7 | |||
Depreciation, amortization and accretion | 1,961.5 | 1,848.3 | 1,687.0 | ||||
Impairment of goodwill | 296.3 | 0.0 | 0.0 | ||||
Impairment of assets other than goodwill | 594.3 | 132.7 | 50.5 | ||||
Net gains attributable to asset sales | (4.4) | (5.7) | (28.7) | ||||
General and administrative costs | 219.6 | 211.7 | 208.3 | ||||
Total costs and expenses | 22,590.7 | 27,273.5 | 31,605.6 | ||||
Vitol Holding B.V. [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | $ 3,314.8 | ||||||
Revenues [Member] | Vitol Holding B.V. [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Percent of revenues | 10.10% | ||||||
NGL Pipelines and Services [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | 11,177.2 | $ 13,470.7 | 15,648.9 | ||||
Operating costs and expenses: | |||||||
Impairment of goodwill | 0.0 | ||||||
NGL Pipelines and Services [Member] | Vitol Holding B.V. [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | 1,410.8 | ||||||
Crude Oil Pipelines & Services [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | 6,689.0 | 10,287.3 | 11,042.6 | ||||
Operating costs and expenses: | |||||||
Impairment of goodwill | 0.0 | ||||||
Crude Oil Pipelines & Services [Member] | Vitol Holding B.V. [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | 1,670.7 | ||||||
Natural Gas Pipelines & Services [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | 2,553.1 | 3,169.4 | 3,454.4 | ||||
Operating costs and expenses: | |||||||
Impairment of goodwill | 296.3 | ||||||
Natural Gas Pipelines & Services [Member] | Vitol Holding B.V. [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | 31.2 | ||||||
Petrochemical and Refined Products Services [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | 6,780.4 | 5,861.8 | $ 6,388.3 | ||||
Operating costs and expenses: | |||||||
Impairment of goodwill | $ 0.0 | ||||||
Petrochemical and Refined Products Services [Member] | Vitol Holding B.V. [Member] | |||||||
Consolidated Revenues [Abstract] | |||||||
Total consolidated revenues | $ 202.1 | ||||||
|
Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions |
12 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||
BASIC EARNINGS PER COMMON UNIT | |||||||
Net income attributable to common unitholders | $ 3,774.7 | $ 4,591.3 | $ 4,172.4 | ||||
Earnings allocated to phantom unit awards | [1] | (32.0) | (27.7) | (21.5) | |||
Net income allocated to common unitholders | $ 3,742.7 | $ 4,563.6 | $ 4,150.9 | ||||
Basic weighted-average number of common units outstanding (in units) | 2,185.8 | 2,188.6 | 2,176.5 | ||||
Basic earnings per common unit (in dollars per unit) | $ 1.71 | $ 2.09 | $ 1.91 | ||||
DILUTED EARNINGS PER COMMON UNIT | |||||||
Net income attributable to common unitholders | $ 3,774.7 | $ 4,591.3 | $ 4,172.4 | ||||
Net income attributable to preferred units | 0.9 | 0.0 | 0.0 | ||||
Net income attributable to limited partners | $ 3,775.6 | $ 4,591.3 | $ 4,172.4 | ||||
Diluted weighted-average number of units outstanding: | |||||||
Distribution-bearing common units (in units) | 2,185.8 | 2,188.6 | 2,176.5 | ||||
Phantom units (in units) | [2] | 15.7 | 13.1 | 10.5 | |||
Preferred units (in units) | [2] | 0.7 | 0.0 | 0.0 | |||
Total (in units) | 2,202.2 | 2,201.7 | 2,187.0 | ||||
Diluted earnings per common unit (in dollars per unit) | $ 1.71 | $ 2.09 | $ 1.91 | ||||
|
Business Combinations (Details) - USD ($) $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
Mar. 29, 2018 |
|
Business Combination | ||||
Investments in unconsolidated affiliates | $ 2,429.2 | $ 2,600.2 | $ 2,615.1 | |
Gain on step acquisition of Delaware Processing | 0.0 | 0.0 | 39.4 | |
Cash used for business combinations, net of cash received | $ 0.0 | $ 0.0 | 150.6 | |
Delaware Basin Gas Processing LLC [Member] | ||||
Business Combination | ||||
Business acquisition, description | Delaware Processing owns a cryogenic natural gas processing facility having a capacity of 150 million cubic feet per day (“MMcf/d”). The facility, which is located in Reeves County, Texas and entered service in August 2016, serves producers in the Delaware Basin in West Texas and southern New Mexico. | |||
Remaining membership interest acquired | 50.00% | |||
Ownership interest | 50.00% | |||
Investments in unconsolidated affiliates | $ 107.0 | |||
Gain on step acquisition of Delaware Processing | 39.4 | |||
Cash used for business combinations, net of cash received | $ 151.0 |
Business Combinations, Purchase Price Allocation (Details) - USD ($) $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Mar. 29, 2018 |
|
Liabilities assumed in business combination: | ||||
Goodwill | $ 5,745.2 | $ 5,448.9 | $ 5,745.2 | |
Delaware Basin Gas Processing LLC [Member] | ||||
Consideration: | ||||
Purchase price for remaining 50% equity interest in Delaware Processing | 154.5 | |||
Fair value of our 50% equity interest in Delaware Processing held before the acquisition | 146.4 | |||
Total consideration | $ 300.9 | |||
Assets acquired in business combination: | ||||
Current assets, including cash | $ 10.8 | |||
Property, plant, and equipment | 200.0 | |||
Total assets acquired | 303.3 | |||
Liabilities assumed in business combination: | ||||
Current liabilities | (1.8) | |||
Long-term liabilities | (0.6) | |||
Total liabilities assumed | (2.4) | |||
Total identifiable net assets | 300.9 | |||
Goodwill | 0.0 | |||
Description of Business Combination: | ||||
Cash acquired | 3.9 | |||
Delaware Basin Gas Processing LLC [Member] | Contract-based intangibles [Member] | ||||
Assets acquired in business combination: | ||||
Intangible assets | 82.6 | |||
Delaware Basin Gas Processing LLC [Member] | Customer relationship intangibles [Member] | ||||
Assets acquired in business combination: | ||||
Intangible assets | $ 9.9 |
Equity-Based Awards (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Equity-based compensation expense [Abstract] | |||
Total compensation expense | $ 159.1 | $ 143.9 | $ 106.1 |
Phantom Unit Awards [Member] | |||
Equity-based compensation expense [Abstract] | |||
Total compensation expense | 150.3 | 132.2 | 99.7 |
Profits Interest Awards [Member] | |||
Equity-based compensation expense [Abstract] | |||
Total compensation expense | 8.7 | 11.6 | 6.1 |
Liability-classified awards [Member] | |||
Equity-based compensation expense [Abstract] | |||
Total compensation expense | $ 0.1 | $ 0.1 | $ 0.3 |
Long-Term Incentive Plan (2008) [Member] | |||
Equity-based compensation expense [Abstract] | |||
Incremental number of units to be authorized annually (in units) | 5,000,000 | ||
Maximum number of additional units to be authorized for issuance (in units) | 70,000,000 | ||
Maximum number of common units that may be issued as awards (in units) | 55,000,000 | ||
Remaining number of common units available to be issued as awards (in units) | 16,229,995 |
Equity-Based Awards, Phantom Unit Awards (Details) - USD ($) $ / shares in Units, $ in Millions |
12 Months Ended | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
||||||||||||
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract] | ||||||||||||||
Cash payments made in connection with DERs | $ 27.1 | $ 22.1 | $ 17.7 | |||||||||||
Phantom Unit Awards [Member] | ||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||||||
Vesting rate of phantom unit awards | 25.00% | |||||||||||||
Summary of awards activity, equity instruments other than options [Roll Forward] | ||||||||||||||
Beginning of period (in units) | 12,974,684 | 10,333,277 | 9,289,501 | |||||||||||
Granted (in units) | 7,405,245 | [1] | 6,854,920 | [2] | 5,006,181 | [3] | ||||||||
Vested (in units) | (4,532,269) | (3,895,049) | (3,479,958) | |||||||||||
Forfeited (in units) | (178,218) | (318,464) | (482,447) | |||||||||||
End of period (in units) | 15,669,442 | 12,974,684 | 10,333,277 | |||||||||||
Common units issued in connection with the vesting of phantom unit awards, net (in units) | 3,162,095 | 2,720,603 | 2,442,436 | |||||||||||
Phantom units outstanding, weighted-average grant date fair value [Roll Forward] | ||||||||||||||
Weighted-average grant date fair value per unit, at beginning of period (in dollars per unit) | [4] | $ 27.21 | $ 26.97 | $ 27.65 | ||||||||||
Granted weighted-average grant date fair value per unit (in dollars per unit) | [4] | 25.71 | [1] | 27.75 | [2] | 26.82 | [3] | |||||||
Vested weighted-average grant date fair value per unit (in dollars per unit) | [4] | 26.35 | 27.53 | 28.57 | ||||||||||
Forfeited weighted-average grant date fair value per unit (in dollars per unit) | [4] | 26.73 | 27.21 | 26.88 | ||||||||||
Weighted-average grant date fair value per unit, at end of period (in dollars per unit) | [4] | $ 26.76 | $ 27.21 | $ 26.97 | ||||||||||
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract] | ||||||||||||||
Aggregate grant date fair value | $ 190.4 | $ 190.2 | $ 134.3 | |||||||||||
Estimated forfeiture rate | 2.40% | 3.00% | 3.20% | |||||||||||
Cash payments made in connection with DERs | $ 27.1 | $ 22.1 | $ 17.7 | |||||||||||
Total intrinsic value of phantom unit awards that vested during period | 114.8 | $ 111.1 | $ 90.7 | |||||||||||
Unrecognized Compensation Expense [Abstract] | ||||||||||||||
Unrecognized compensation cost | $ 156.7 | |||||||||||||
Recognition period for total unrecognized compensation cost | 2 years | |||||||||||||
Phantom Unit Awards [Member] | Minimum [Member] | ||||||||||||||
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract] | ||||||||||||||
Grant date market price of common units (in dollars per unit) | $ 16.95 | $ 26.32 | $ 25.40 | |||||||||||
Phantom Unit Awards [Member] | Maximum [Member] | ||||||||||||||
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract] | ||||||||||||||
Grant date market price of common units (in dollars per unit) | $ 25.76 | $ 29.29 | $ 29.22 | |||||||||||
Phantom Unit Awards [Member] | Enterprise [Member] | ||||||||||||||
Unrecognized Compensation Expense [Abstract] | ||||||||||||||
Unrecognized compensation cost | $ 129.6 | |||||||||||||
|
Equity-Based Awards, Profits Interest Awards (Details) $ / shares in Units, $ in Millions |
12 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|
Dec. 31, 2020
USD ($)
$ / shares
shares
| ||||||||
EPD PubCo II [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Exercise price (in dollars per unit) | $ / shares | $ 25.41 | |||||||
Incremental cost due to plan modification | $ 1.2 | |||||||
Vesting period | 30 days | |||||||
Partnership common units contributed by EPCO Holdings (in units) | shares | 2,834,198 | |||||||
Class A capital base | $ 66.3 | [1] | ||||||
Class A preference return | $ / shares | $ 0.3900 | |||||||
Estimated fair value of profits interest awards | $ 2.5 | [2] | ||||||
Unrecognized Compensation Expense [Abstract] | ||||||||
Unrecognized compensation cost | $ 2.3 | [3] | ||||||
Recognition period for total unrecognized compensation cost | 2 years 1 month 6 days | |||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Expected life of award from grant date | 7 years | |||||||
EPD PubCo II [Member] | Minimum [Member] | ||||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Risk-free interest rate | 0.10% | |||||||
Expected distribution yield | 5.90% | |||||||
Expected unit price volatility | 19.00% | |||||||
EPD PubCo II [Member] | Maximum [Member] | ||||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Risk-free interest rate | 3.00% | |||||||
Expected distribution yield | 7.00% | |||||||
Expected unit price volatility | 40.00% | |||||||
EPD PrivCo I [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Exercise price (in dollars per unit) | $ / shares | $ 25.41 | |||||||
Incremental cost due to plan modification | $ 0.5 | |||||||
Vesting period | 30 days | |||||||
Partnership common units contributed by EPCO Holdings (in units) | shares | 1,111,438 | |||||||
Class A capital base | $ 26.0 | [1] | ||||||
Class A preference return | $ / shares | $ 0.3900 | |||||||
Estimated fair value of profits interest awards | $ 0.9 | [2] | ||||||
Unrecognized Compensation Expense [Abstract] | ||||||||
Unrecognized compensation cost | $ 0.2 | [3] | ||||||
Recognition period for total unrecognized compensation cost | 2 years 1 month 6 days | |||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Expected life of award from grant date | 7 years | |||||||
EPD PrivCo I [Member] | Minimum [Member] | ||||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Risk-free interest rate | 0.10% | |||||||
Expected distribution yield | 6.10% | |||||||
Expected unit price volatility | 19.00% | |||||||
EPD PrivCo I [Member] | Maximum [Member] | ||||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Risk-free interest rate | 1.60% | |||||||
Expected distribution yield | 6.70% | |||||||
Expected unit price volatility | 40.00% | |||||||
EPD IV [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Vesting period | 30 days | |||||||
Partnership common units contributed by EPCO Holdings (in units) | shares | 6,400,000 | |||||||
Class A capital base | $ 172.9 | [1] | ||||||
Class A preference return | $ / shares | $ 0.4325 | |||||||
Estimated fair value of profits interest awards | $ 26.7 | [2] | ||||||
Unrecognized Compensation Expense [Abstract] | ||||||||
Unrecognized compensation cost | $ 13.6 | [3] | ||||||
Recognition period for total unrecognized compensation cost | 2 years 10 months 24 days | |||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Expected life of award from grant date | 5 years | |||||||
EPD IV [Member] | Minimum [Member] | ||||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Risk-free interest rate | 2.80% | |||||||
Expected distribution yield | 6.50% | |||||||
Expected unit price volatility | 27.00% | |||||||
EPD IV [Member] | Maximum [Member] | ||||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Risk-free interest rate | 2.80% | |||||||
Expected distribution yield | 6.50% | |||||||
Expected unit price volatility | 27.00% | |||||||
EPCO Unit II [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Vesting period | 30 days | |||||||
Partnership common units contributed by EPCO Holdings (in units) | shares | 1,600,000 | |||||||
Class A capital base | $ 43.2 | [1] | ||||||
Class A preference return | $ / shares | $ 0.4325 | |||||||
Estimated fair value of profits interest awards | $ 6.6 | [2] | ||||||
Unrecognized Compensation Expense [Abstract] | ||||||||
Unrecognized compensation cost | $ 0.3 | [3] | ||||||
Recognition period for total unrecognized compensation cost | 2 years 10 months 24 days | |||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Expected life of award from grant date | 5 years | |||||||
EPCO Unit II [Member] | Minimum [Member] | ||||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Risk-free interest rate | 1.60% | |||||||
Expected distribution yield | 6.30% | |||||||
Expected unit price volatility | 24.00% | |||||||
EPCO Unit II [Member] | Maximum [Member] | ||||||||
Estimated Grant Date Fair Value Assumptions [Abstract] | ||||||||
Risk-free interest rate | 2.80% | |||||||
Expected distribution yield | 6.80% | |||||||
Expected unit price volatility | 27.00% | |||||||
|
Hedging Activities and Fair Value Measurements (Details) bbl in Millions, $ in Millions, ft³ in Billions |
12 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2020
USD ($)
Contract
bbl
ft³
|
Dec. 31, 2019
USD ($)
|
Dec. 31, 2018
USD ($)
|
|||||||||
Derivative [Line Items] | |||||||||||
Payments for the settlement of interest rate derivative instruments | $ | $ (33.3) | $ 0.0 | $ 22.1 | ||||||||
Gain on the sale of swaption | $ | 23.1 | 29.4 | |||||||||
Carrying amount of hedged asset | $ | 144.0 | $ 31.7 | |||||||||
Forward Starting Swaps [Member] | Derivatives in cash flow hedging relationships [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Notional Amount | $ | $ 1,080.0 | ||||||||||
Weighted-Average Rate Locked | 1.83% | ||||||||||
Life of associated future debt | 30 years | ||||||||||
Notional amount of settled derivative instruments | $ | $ 575.0 | 275.0 | |||||||||
Payments for the settlement of interest rate derivative instruments | $ | $ (33.3) | $ 22.1 | |||||||||
Forward Starting Swaps - May 2019 [Member] | Derivatives in cash flow hedging relationships [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Number of Derivatives Outstanding | Contract | 1 | ||||||||||
Notional Amount | $ | $ 75.0 | ||||||||||
Weighted-Average Rate Locked | 2.41% | ||||||||||
Forward Starting Swaps - September 2019 [Member] | Derivatives in cash flow hedging relationships [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Number of Derivatives Outstanding | Contract | 10 | ||||||||||
Notional Amount | $ | $ 1,000.0 | ||||||||||
Forward Starting Swaps D [Member] | Derivatives in cash flow hedging relationships [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Number of Derivatives Outstanding | Contract | 5 | ||||||||||
Notional Amount | $ | $ 500.0 | ||||||||||
Weighted-Average Rate Locked | 2.13% | ||||||||||
Forward Starting Swaps - January 2020 [Member] | Derivatives in cash flow hedging relationships [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Number of Derivatives Outstanding | Contract | [1] | 2 | |||||||||
Notional Amount | $ | $ 150.0 | ||||||||||
Weighted-Average Rate Locked | 1.72% | ||||||||||
Forward Starting Swaps - February 2020 (A) [Member] | Derivatives in cash flow hedging relationships [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Number of Derivatives Outstanding | Contract | [1] | 1 | |||||||||
Notional Amount | $ | $ 100.0 | ||||||||||
Weighted-Average Rate Locked | 1.46% | ||||||||||
Forward Starting Swaps - February 2020 (B) [Member] | Derivatives in cash flow hedging relationships [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Number of Derivatives Outstanding | Contract | [1] | 2 | |||||||||
Notional Amount | $ | $ 150.0 | ||||||||||
Weighted-Average Rate Locked | 1.48% | ||||||||||
Forward Starting Swaps - March 2020 [Member] | Derivatives in cash flow hedging relationships [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Number of Derivatives Outstanding | Contract | [1] | 2 | |||||||||
Notional Amount | $ | $ 100.0 | ||||||||||
Weighted-Average Rate Locked | 0.95% | ||||||||||
Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (PTR) [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | ft³ | [2],[3] | 6.0 | |||||||||
Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted sales of NGLs [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 0.6 | |||||||||
Designated as Hedging Instrument [Member] | Natural gas marketing: Natural gas storage inventory management activities [Member] | Derivatives in fair value hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | ft³ | [2],[3] | 4.0 | |||||||||
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 142.8 | |||||||||
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 1.6 | |||||||||
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 172.1 | |||||||||
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 4.5 | |||||||||
Designated as Hedging Instrument [Member] | NGL marketing: NGLs inventory management activities [Member] | Derivatives in fair value hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 1.9 | |||||||||
Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted purchases of refined products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 41.2 | |||||||||
Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted sales of refined products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 51.1 | |||||||||
Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted sales of refined products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 3.3 | |||||||||
Designated as Hedging Instrument [Member] | Refined products marketing: Refined products inventory management activities [Member] | Derivatives in fair value hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 0.8 | |||||||||
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 32.9 | |||||||||
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted sales of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 44.5 | |||||||||
Designated as Hedging Instrument [Member] | Petrochemical marketing: Forecasted purchases of petrochemical products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 0.4 | |||||||||
Designated as Hedging Instrument [Member] | Petrochemical marketing: Forecasted sales of petrochemical products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3] | 0.5 | |||||||||
Not Designated as Hedging Instrument [Member] | Natural gas risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | ft³ | [2],[3],[4] | 10.3 | |||||||||
Not Designated as Hedging Instrument [Member] | Natural gas risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | ft³ | [2],[3],[4] | 0.4 | |||||||||
Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3],[4] | 26.5 | |||||||||
Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3],[4] | 7.9 | |||||||||
Not Designated as Hedging Instrument [Member] | Refined products risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3],[4] | 6.9 | |||||||||
Not Designated as Hedging Instrument [Member] | Crude oil risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3],[4] | 32.5 | |||||||||
Not Designated as Hedging Instrument [Member] | Crude oil risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member] | |||||||||||
Derivative [Line Items] | |||||||||||
Volume | [2],[3],[4] | 2.6 | |||||||||
|
Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Interest rate derivatives [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | $ 12.4 | |
Liability Derivatives | 120.1 | $ 13.5 |
Commodity derivatives [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 229.2 | 127.8 |
Liability Derivatives | 246.3 | 116.2 |
Derivatives designated as hedging instruments [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 223.3 | 116.5 |
Liability Derivatives | 360.2 | 120.6 |
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 12.4 | 0.0 |
Liability Derivatives | 120.1 | 13.5 |
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 0.0 | 0.0 |
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 12.4 | 0.0 |
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | 109.1 | 6.7 |
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Other liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | 11.0 | 6.8 |
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 210.9 | 116.5 |
Liability Derivatives | 240.1 | 107.1 |
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 210.5 | 116.5 |
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 0.4 | 0.0 |
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | 234.0 | 107.1 |
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | 6.1 | 0.0 |
Derivatives not designated as hedging instruments [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 18.3 | 11.3 |
Liability Derivatives | 6.2 | 9.1 |
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 18.3 | 11.3 |
Liability Derivatives | 6.2 | 9.1 |
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 18.1 | 10.7 |
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Asset Derivatives | 0.2 | 0.6 |
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | 6.1 | 8.6 |
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Liability Derivatives | $ 0.1 | $ 0.5 |
Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Interest rate derivatives [Member] | ||
Offsetting Assets [Line Items] | ||
Gross Amounts of Recognized Assets | $ 12.4 | |
Gross Amounts Offset in the Balance Sheet | 0.0 | |
Amounts of Assets Presented in the Balance Sheet | 12.4 | |
Financial Instruments | 0.0 | |
Cash Collateral Paid | 0.0 | |
Cash Collateral Received | 0.0 | |
Amounts That Would Have Been Presented On Net Basis | 12.4 | |
Commodity Derivatives [Member] | ||
Offsetting Assets [Line Items] | ||
Gross Amounts of Recognized Assets | 229.2 | $ 127.8 |
Gross Amounts Offset in the Balance Sheet | 0.0 | 0.0 |
Amounts of Assets Presented in the Balance Sheet | 229.2 | 127.8 |
Financial Instruments | (228.5) | (115.3) |
Cash Collateral Paid | 0.0 | (11.0) |
Cash Collateral Received | 0.0 | 0.0 |
Amounts That Would Have Been Presented On Net Basis | $ 0.7 | $ 1.5 |
Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Interest rate derivatives [Member] | ||
Offsetting Liabilities [Line Items] | ||
Gross Amounts of Recognized Liabilities | $ 120.1 | $ 13.5 |
Gross Amounts Offset in the Balance Sheet | 0.0 | 0.0 |
Amounts of Liabilities Presented in the Balance Sheet | 120.1 | 13.5 |
Financial Instruments | 0.0 | 0.0 |
Cash Collateral Paid | 0.0 | 0.0 |
Amounts That Would Have Been Presented On Net Basis | 120.1 | 13.5 |
Commodity Derivatives [Member] | ||
Offsetting Liabilities [Line Items] | ||
Gross Amounts of Recognized Liabilities | 246.3 | 116.2 |
Gross Amounts Offset in the Balance Sheet | 0.0 | 0.0 |
Amounts of Liabilities Presented in the Balance Sheet | 246.3 | 116.2 |
Financial Instruments | (228.5) | (115.3) |
Cash Collateral Paid | (17.3) | 0.0 |
Amounts That Would Have Been Presented On Net Basis | $ 0.5 | $ 0.9 |
Hedging Activities and Fair Value Measurements, Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($) $ in Millions |
12 Months Ended | ||||
---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Unrealized gains (losses) | $ 79.3 | $ 67.7 | $ (17.7) | ||
Mark-to-market loss in interest expense | 0.0 | (94.9) | (0.1) | ||
Total mark-to-market gains (losses) | 79.3 | (27.2) | (17.8) | ||
NGL Pipelines & Services [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Unrealized gains (losses) | 48.4 | (5.5) | 18.0 | ||
Crude Oil Pipelines & Services [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Unrealized gains (losses) | 20.1 | 80.6 | (44.1) | ||
Natural Gas Pipelines & Services [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Unrealized gains (losses) | 6.3 | (0.2) | 6.7 | ||
Petrochemical & Refined Products Services [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Unrealized gains (losses) | 4.5 | (7.2) | 1.7 | ||
Derivatives in fair value hedging relationships [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) Recognized in Income on Derivative | (88.0) | 2.2 | 11.2 | ||
Gain (Loss) Recognized in Income on Hedged Item | 168.1 | 6.9 | (8.3) | ||
Derivatives in fair value hedging relationships [Member] | Interest rate derivatives [Member] | Interest expense [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) Recognized in Income on Derivative | 0.0 | 0.0 | 1.3 | ||
Gain (Loss) Recognized in Income on Hedged Item | 0.0 | 0.0 | (1.4) | ||
Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member] | Revenue [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) Recognized in Income on Derivative | (88.0) | 2.2 | 9.9 | ||
Gain (Loss) Recognized in Income on Hedged Item | 168.1 | 6.9 | (6.9) | ||
Derivatives in cash flow hedging relationships [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative | (3.1) | 125.5 | 315.4 | ||
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income | 233.4 | 104.4 | 92.3 | ||
Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative | (127.5) | 81.4 | 22.2 | ||
Accumulated other comprehensive loss related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months | (41.2) | ||||
Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member] | Interest expense [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income | (39.3) | (37.3) | (38.1) | ||
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months | (35.6) | ||||
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months | (36.0) | ||||
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to operating costs and expenses over the next twelve months | 0.4 | ||||
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Revenue [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative | [1] | 134.7 | 55.8 | 293.0 | |
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income | 282.6 | 152.4 | 131.7 | ||
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Operating costs and expenses [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative | [1] | (10.3) | (11.7) | 0.2 | |
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income | (9.9) | (10.7) | (1.3) | ||
Derivatives not designated as hedging instruments [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) Recognized in Income on Derivative | 165.8 | (5.1) | (454.7) | ||
Derivatives not designated as hedging instruments [Member] | Interest rate derivatives [Member] | Interest expense [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) Recognized in Income on Derivative | 0.0 | (94.9) | 0.0 | ||
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Realized gains (losses) | 92.1 | ||||
Unrealized gains (losses) | 73.7 | ||||
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Revenue [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) Recognized in Income on Derivative | 166.0 | 102.2 | (462.9) | ||
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Operating costs and expenses [Member] | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Gain (Loss) Recognized in Income on Derivative | $ (0.2) | $ (12.4) | $ 8.2 | ||
|
Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - USD ($) $ in Millions |
12 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
Mar. 05, 2020 |
|||||
Financial liabilities [Abstract] | ||||||||
Liquidity Option | $ 0.0 | $ 509.6 | $ 511.9 | |||||
Total gains (losses) included in: | ||||||||
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities | 79.3 | (27.2) | $ (17.8) | |||||
Fair Value, Measurements, Recurring [Member] | ||||||||
Financial assets [Abstract] | ||||||||
Interest rate derivatives | 12.4 | |||||||
Value before application of CME Rule 814 | 1,570.1 | 397.2 | ||||||
Impact of CME Rule 814 | (1,340.9) | (269.4) | ||||||
Total commodity derivatives | 229.2 | 127.8 | ||||||
Total | 241.6 | 127.8 | ||||||
Financial liabilities [Abstract] | ||||||||
Liquidity Option | 509.6 | |||||||
Interest rate derivatives | 120.1 | 13.5 | ||||||
Commodity derivatives: | ||||||||
Value before application of CME Rule 814 | 2,138.9 | 362.0 | ||||||
Impact of CME Rule 814 | (1,892.6) | (245.8) | ||||||
Total commodity derivatives | 246.3 | 116.2 | ||||||
Total | 366.4 | 639.3 | ||||||
Net value before application of CME Rule 814 to commodity hedging portfolio | (568.8) | |||||||
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | ||||||||
Financial assets [Abstract] | ||||||||
Interest rate derivatives | 0.0 | |||||||
Value before application of CME Rule 814 | 678.6 | 53.4 | ||||||
Impact of CME Rule 814 | (678.6) | (47.0) | ||||||
Total commodity derivatives | 0.0 | 6.4 | ||||||
Total | 0.0 | 6.4 | ||||||
Financial liabilities [Abstract] | ||||||||
Liquidity Option | 0.0 | |||||||
Interest rate derivatives | 0.0 | 0.0 | ||||||
Commodity derivatives: | ||||||||
Value before application of CME Rule 814 | 1,065.6 | 88.1 | ||||||
Impact of CME Rule 814 | (1,065.6) | (81.9) | ||||||
Total commodity derivatives | 0.0 | 6.2 | ||||||
Total | 0.0 | 6.2 | ||||||
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | ||||||||
Financial assets [Abstract] | ||||||||
Interest rate derivatives | 12.4 | |||||||
Value before application of CME Rule 814 | 878.6 | 343.7 | ||||||
Impact of CME Rule 814 | (650.4) | (222.4) | ||||||
Total commodity derivatives | 228.2 | 121.3 | ||||||
Total | 240.6 | 121.3 | ||||||
Financial liabilities [Abstract] | ||||||||
Liquidity Option | 0.0 | |||||||
Interest rate derivatives | 120.1 | 13.5 | ||||||
Commodity derivatives: | ||||||||
Value before application of CME Rule 814 | 1,047.4 | 273.6 | ||||||
Impact of CME Rule 814 | (807.3) | (163.9) | ||||||
Total commodity derivatives | 240.1 | 109.7 | ||||||
Total | 360.2 | 123.2 | ||||||
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | ||||||||
Financial assets [Abstract] | ||||||||
Interest rate derivatives | 0.0 | |||||||
Value before application of CME Rule 814 | 12.9 | 0.1 | ||||||
Impact of CME Rule 814 | (11.9) | 0.0 | ||||||
Total commodity derivatives | 1.0 | 0.1 | ||||||
Total | 1.0 | 0.1 | ||||||
Financial liabilities [Abstract] | ||||||||
Liquidity Option | 509.6 | |||||||
Interest rate derivatives | 0.0 | 0.0 | ||||||
Commodity derivatives: | ||||||||
Value before application of CME Rule 814 | 25.9 | 0.3 | ||||||
Impact of CME Rule 814 | (19.7) | 0.0 | ||||||
Total commodity derivatives | 6.2 | 0.3 | ||||||
Total | 6.2 | 509.9 | ||||||
Reconciliation of changes in the fair value of Level 3 financial assets and liabilities [Roll Forward] | ||||||||
Financial liability balance, net, beginning of period | (509.8) | (395.9) | ||||||
Total gains (losses) included in: | ||||||||
Transfer out of Level 3 - Liquidity Option | [1] | 511.9 | 0.0 | |||||
Other transfers out of Level 3 | 17.1 | 7.6 | ||||||
Financial liability balance, net, end of period | (5.2) | (509.8) | $ (395.9) | |||||
Unrealized gain (loss) recognized as a component of net income related to financial assets and liabilities | 0.7 | 0.2 | ||||||
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Other Comprehensive Income (Loss) [Member] | ||||||||
Total gains (losses) included in: | ||||||||
Other comprehensive income (loss) | (23.7) | (2.1) | ||||||
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Revenue [Member] | ||||||||
Total gains (losses) included in: | ||||||||
Net income | [2] | (1.6) | 3.7 | |||||
Settlements | [2] | 3.2 | (3.5) | |||||
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Other Expense [Member] | ||||||||
Total gains (losses) included in: | ||||||||
Net income | $ (2.3) | $ (119.6) | ||||||
|
Hedging Activities and Fair Value Measurements, Nonrecurring Fair Value Measurements (Details) $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2020
USD ($)
| ||||
South Texas natural gas gathering and processing assets [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | $ 21.3 | |||
Asset Impairment Charges [Abstract] | ||||
Impairment of long-lived assets held and used | 125.7 | |||
Marine transportation business [Member] | ||||
Asset Impairment Charges [Abstract] | ||||
Impairment of long-lived assets held and used | $ 256.7 | |||
Marine transportation business [Member] | Measurement input, discount rate [Member] | ||||
Asset Impairment Charges [Abstract] | ||||
Long-lived asset, measurement input | 0.093 | |||
Marine transportation business [Member] | Measurement input, growth rate [Member] | ||||
Asset Impairment Charges [Abstract] | ||||
Long-lived asset, measurement input | 0.021 | |||
Petrochemical and Refined Products Services [Member] | Marine transportation business [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | $ 410.0 | |||
Fair Value, Measurements, Nonrecurring [Member] | South Texas natural gas gathering and processing assets [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | 21.3 | [1] | ||
Fair Value, Measurements, Nonrecurring [Member] | Marine transportation business [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | 410.0 | [1] | ||
Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | South Texas natural gas gathering and processing assets [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | 0.0 | [1] | ||
Fair Value, Measurements, Nonrecurring [Member] | Level 1 [Member] | Marine transportation business [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | 0.0 | [1] | ||
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | South Texas natural gas gathering and processing assets [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | 0.0 | [1] | ||
Fair Value, Measurements, Nonrecurring [Member] | Level 2 [Member] | Marine transportation business [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | 0.0 | [1] | ||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | South Texas natural gas gathering and processing assets [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | 21.3 | [1] | ||
Fair Value, Measurements, Nonrecurring [Member] | Level 3 [Member] | Marine transportation business [Member] | ||||
Assets, Fair Value Disclosure [Abstract] | ||||
Assets, fair value | $ 410.0 | [1] | ||
|
Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Carrying Value [Member] | ||
Financial Liabilities: [Abstract] | ||
Fixed-rate debt obligations | $ 29,900 | $ 27,150 |
Level 2 [Member] | Fair Value [Member] | ||
Financial Liabilities: [Abstract] | ||
Fixed-rate debt obligations | $ 35,000 | $ 30,370 |
Related Party Transactions (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Revenues - related parties: | |||
Total revenue - related parties | $ 36.7 | $ 67.3 | $ 107.7 |
Costs and expenses - related parties: | |||
Operating costs and expenses | 1,210.6 | 1,412.0 | 1,406.1 |
General and administrative expenses | 136.2 | 136.4 | 130.9 |
Total costs and expenses - related parties | 1,346.8 | 1,548.4 | 1,537.0 |
Accounts receivable - related parties: | |||
Total accounts receivable - related parties | 5.6 | 2.5 | |
Accounts payable - related parties: | |||
Total accounts payable - related parties | 149.5 | 162.3 | |
EPCO and its privately held affiliates [Member] | |||
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | 1,143.7 | 1,145.3 | 1,089.6 |
Accounts receivable - related parties: | |||
Total accounts receivable - related parties | 1.9 | 0.0 | |
Accounts payable - related parties: | |||
Total accounts payable - related parties | 139.6 | 143.7 | |
Distributions: | |||
Total cash distributions | 1,210.0 | 1,190.0 | 1,160.0 |
EPCO and its privately held affiliates [Member] | Distribution Reinvestment Plan [Member] | |||
Relationship with Affiliates [Abstract] | |||
Gross proceeds from the sale of common units | 29.0 | 213.0 | |
EPCO and its privately held affiliates [Member] | Administrative Services Agreement [Member] | |||
Costs and expenses - related parties: | |||
Operating costs and expenses | 999.0 | 1,000.2 | 948.8 |
General and administrative expenses | 128.9 | 127.6 | 124.2 |
Total costs and expenses - related parties | 1,127.9 | 1,127.8 | 1,073.0 |
EPCO and its privately held affiliates [Member] | Related Party Operating Leases [Member] | |||
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | $ 13.0 | 14.9 | 13.9 |
EPCO and its privately held affiliates [Member] | Common Units [Member] | |||
Relationship with Affiliates [Abstract] | |||
Number of Units (in units) | 701,993,298 | ||
Percentage of total units outstanding | 32.20% | ||
Enterprise common units pledged as security (in units) | 92,976,464 | ||
EPCO and its privately held affiliates [Member] | Preferred Units [Member] | |||
Relationship with Affiliates [Abstract] | |||
Number of Units (in units) | 15,138 | ||
Percentage of total units outstanding | 30.20% | ||
Unconsolidated affiliates [Member] | |||
Revenues - related parties: | |||
Total revenue - related parties | $ 36.7 | 67.3 | 107.7 |
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | 203.1 | 403.1 | 447.4 |
Accounts receivable - related parties: | |||
Total accounts receivable - related parties | 3.7 | 2.5 | |
Accounts payable - related parties: | |||
Total accounts payable - related parties | 9.9 | 18.6 | |
Unconsolidated affiliates [Member] | Seaway Crude Holdings LLC [Member] | |||
Revenues - related parties: | |||
Total revenue - related parties | 20.2 | 42.7 | 74.4 |
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | 71.5 | 194.5 | 163.2 |
Unconsolidated affiliates [Member] | Venice Energy Service Company, L.L.C. [Member] | |||
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | 51.3 | 89.2 | 157.9 |
Unconsolidated affiliates [Member] | K/D/S Promix, L.L.C. [Member] | |||
Revenues - related parties: | |||
Total revenue - related parties | 6.0 | 9.1 | 9.5 |
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | 23.5 | 34.8 | 31.9 |
Unconsolidated affiliates [Member] | Texas Express Pipeline LLC [Member] | |||
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | 29.1 | 33.5 | 57.6 |
Unconsolidated affiliates [Member] | Eagle Ford Pipeline LLC [Member] | |||
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | 20.9 | 36.0 | 18.5 |
Unconsolidated affiliates [Member] | Management/Operator Fees [Member] | |||
Costs and expenses - related parties: | |||
Total costs and expenses - related parties | $ (10.1) | $ (9.9) | $ (11.6) |
Income Taxes (Details) - USD ($) $ / shares in Units, $ in Millions |
10 Months Ended | 12 Months Ended | |||||
---|---|---|---|---|---|---|---|
Mar. 05, 2020 |
Dec. 31, 2020 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||
Components of Benefit From (Provision For) Income Taxes: | |||||||
Maximum percent of qualifying income for publicly traded partnerships to be treated as corporations | 90.00% | ||||||
Texas Margin Tax | [1] | $ (32.1) | $ (44.2) | $ (54.8) | |||
Other | 1.1 | (1.4) | (5.5) | ||||
Benefit from (provision for) income taxes | 124.3 | (45.6) | (60.3) | ||||
Liquidity Option liability | $ 511.9 | $ 0.0 | $ 0.0 | 509.6 | |||
Series A cumulative convertible preferred units (in dollars per unit) | $ 1,000 | $ 1,000 | |||||
OTA Holdings, Inc. [Member] | |||||||
Components of Benefit From (Provision For) Income Taxes: | |||||||
Benefit from (provision for) income taxes | $ 72.2 | $ 83.1 | $ 155.3 | $ 0.0 | $ 0.0 | ||
|
Income Taxes, Benefit From (Provision For) Income Taxes (Details) - USD ($) $ in Millions |
10 Months Ended | 12 Months Ended | |||
---|---|---|---|---|---|
Mar. 05, 2020 |
Dec. 31, 2020 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Current portion of income tax benefit (provision): | |||||
Federal | $ 2.9 | $ 1.3 | $ (5.3) | ||
State | (25.6) | (25.7) | (33.1) | ||
Foreign | (0.6) | (1.2) | (0.5) | ||
Total current portion | (23.3) | (25.6) | (38.9) | ||
Deferred portion of income tax benefit (provision): | |||||
Federal | 142.0 | (1.6) | 0.3 | ||
State | 5.6 | (18.5) | (21.7) | ||
Foreign | 0.0 | 0.1 | 0.0 | ||
Total deferred portion | 147.6 | (20.0) | (21.4) | ||
Total benefit from (provision for) income taxes | 124.3 | (45.6) | (60.3) | ||
OTA Holdings, Inc. [Member] | |||||
Deferred portion of income tax benefit (provision): | |||||
Federal | $ 67.8 | ||||
State | 4.4 | ||||
Total benefit from (provision for) income taxes | $ 72.2 | $ 83.1 | $ 155.3 | $ 0.0 | $ 0.0 |
Income Taxes, Reconciliation of the Benefit From (Provision For) Income Taxes (Details) - USD ($) $ in Millions |
12 Months Ended | ||||||
---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||||
Reconciliation of the benefit from (provision for) income taxes [Abstract] | |||||||
Pre-Tax Net Book Income ("NBI") | $ 3,761.4 | $ 4,732.7 | $ 4,298.8 | ||||
Texas Margin Tax | [1] | (32.1) | (44.2) | (54.8) | |||
State income tax benefit (provision), net of federal benefit | [2] | 9.2 | (0.5) | (0.2) | |||
Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities | 80.1 | (0.9) | (2.1) | ||||
Federal benefit attributable to settlement of Liquidity Option | [2] | 67.8 | 0.0 | 0.0 | |||
Other differences | (0.7) | 0.0 | (3.2) | ||||
Total benefit from (provision for) income taxes | $ 124.3 | $ (45.6) | $ (60.3) | ||||
Effective income tax rate | 3.30% | (1.00%) | (1.40%) | ||||
|
Income Taxes, Deferred Tax Liabilities and Assets (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Mar. 05, 2020 |
Dec. 31, 2019 |
||
---|---|---|---|---|---|
Deferred tax liabilities: | |||||
Attributable to investment in OTA | $ 356.6 | $ 439.7 | $ 0.0 | ||
Attributable to property, plant and equipment | 106.4 | 100.2 | |||
Attributable to investments in other entities | 4.1 | 3.3 | |||
Total deferred tax liabilities | 467.1 | 103.5 | |||
Less: deferred tax assets: | |||||
Net operating loss carryovers | [1] | 0.1 | 0.1 | ||
Temporary differences related to Texas Margin Tax | 2.3 | 3.0 | |||
Total deferred tax assets | 2.4 | 3.1 | |||
Total net deferred tax liabilities | $ 464.7 | $ 100.4 | |||
|
Commitments and Contingent Liabilities (Details) bbl in Millions, $ in Millions, BTU in Trillions |
Dec. 31, 2020
USD ($)
BTU
bbl
|
Mar. 05, 2020
USD ($)
|
Dec. 31, 2019
USD ($)
|
---|---|---|---|
Redelivery commitments: | |||
Redelivery commitments of natural gas | BTU | 9.9 | ||
Redelivery commitments of crude oil | bbl | 19.4 | ||
Redelivery commitments of NGL and petrochemical products | bbl | 31.1 | ||
Operating lease obligations: | |||
Renewal option years for certain leases | 20 years | ||
Liabilities, Other than Long-term Debt, Noncurrent [Abstract] | |||
Noncurrent portion of AROs | $ 137.6 | $ 126.9 | |
Deferred revenues - non-current portion | 198.2 | 197.0 | |
Liquidity Option liability | 0.0 | $ 511.9 | 509.6 |
Lease liability - non-current portion | 320.8 | 171.6 | |
Derivative liabilities | 17.2 | 7.3 | |
Other | 12.8 | 20.0 | |
Total | 686.6 | 1,032.4 | |
Junior Subordinated Note [Member] | |||
Debt Instrument [Line Items] | |||
Debt obligations | $ 2,650.0 | ||
Minimum [Member] | |||
Operating lease obligations: | |||
Term of material lease agreements | 5 years | ||
Maximum [Member] | |||
Operating lease obligations: | |||
Term of material lease agreements | 30 years | ||
Litigation matters [Member] | |||
Loss Contingencies [Line Items] | |||
Litigation accruals on an undiscounted basis | $ 6.1 | $ 0.2 |
Commitments and Contingent Liabilities, Contractual Obligations (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Scheduled maturities of debt obligations [Abstract] | ||
2021 | $ 1,325.0 | |
2022 | 1,400.0 | |
2023 | 1,250.0 | |
2024 | 850.0 | |
2025 | 1,150.0 | |
Thereafter | 24,171.4 | |
Total | 30,146.4 | $ 27,878.4 |
Estimated cash interest payments [Abstract] | ||
2021 | 1,294.0 | |
2022 | 1,241.2 | |
2023 | 1,201.0 | |
2024 | 1,162.8 | |
2025 | 1,121.4 | |
Thereafter | 22,814.2 | |
Total | 28,834.6 | |
Operating lease obligations [Abstract] | ||
2021 | 33.7 | |
2022 | 36.1 | |
2023 | 33.2 | |
2024 | 29.9 | |
2025 | 28.8 | |
Thereafter | 298.8 | |
Total | 460.5 | |
Natural Gas [Member] | ||
Estimated payment obligations: | ||
2021 | 84.6 | |
2022 | 70.4 | |
2023 | 0.0 | |
2024 | 0.0 | |
2025 | 0.0 | |
Thereafter | 0.0 | |
Total | 155.0 | |
NGLs [Member] | ||
Estimated payment obligations: | ||
2021 | 685.2 | |
2022 | 696.8 | |
2023 | 494.4 | |
2024 | 436.4 | |
2025 | 336.8 | |
Thereafter | 1,258.8 | |
Total | 3,908.4 | |
Crude Oil [Member] | ||
Estimated payment obligations: | ||
2021 | 1,390.1 | |
2022 | 1,390.1 | |
2023 | 1,390.1 | |
2024 | 1,354.9 | |
2025 | 1,297.2 | |
Thereafter | 3,543.3 | |
Total | 10,365.7 | |
Petrochemicals And Refined Products [Member] | ||
Estimated payment obligations: | ||
2021 | 100.9 | |
2022 | 100.9 | |
2023 | 76.0 | |
2024 | 68.3 | |
2025 | 0.0 | |
Thereafter | 0.0 | |
Total | 346.1 | |
Estimated Payment Obligations Other [Member] | ||
Estimated payment obligations: | ||
2021 | 5.8 | |
2022 | 5.9 | |
2023 | 6.0 | |
2024 | 5.1 | |
2025 | 2.7 | |
Thereafter | 0.0 | |
Total | 25.5 | |
Service Payment Commitments [Member] | ||
Estimated payment obligations: | ||
2021 | 62.0 | |
2022 | 59.7 | |
2023 | 42.3 | |
2024 | 16.1 | |
2025 | 12.9 | |
Thereafter | 85.8 | |
Total | 278.8 | |
EFS Midstream Contract with Producers [Member] | ||
Contractual obligation [Line Items] | ||
Contractual obligation | 270.0 | |
Capital expenditures to date | $ 151.0 | |
Contract term | 10 years |
Commitments and Contingent Liabilities, Operating Leases (Details) - USD ($) $ in Millions |
12 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|||||||
Operating Leases [Abstract] | ||||||||
ROU asset carrying value | [1] | $ 332.0 | ||||||
Lease liability carrying value | [2] | 348.6 | ||||||
Lease liability, current | $ 27.8 | |||||||
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | us-gaap:OtherLiabilitiesCurrent | |||||||
Lease liability, noncurrent | $ 320.8 | $ 171.6 | ||||||
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | us-gaap:OtherLiabilitiesNoncurrent | |||||||
Increase in ROU asset during the period | $ 121.8 | |||||||
Increase in lease liability during the period | 136.6 | |||||||
Storage and Pipeline Facilities [Member] | ||||||||
Operating Leases [Abstract] | ||||||||
ROU asset carrying value | [1] | 128.0 | ||||||
Lease liability carrying value | [2] | $ 128.7 | ||||||
Weighted-average remaining term | 15 years | |||||||
Weighted-average discount rate | [3] | 4.30% | ||||||
Transportation Equipment [Member] | ||||||||
Operating Leases [Abstract] | ||||||||
ROU asset carrying value | [1] | $ 33.5 | ||||||
Lease liability carrying value | [2] | $ 35.6 | ||||||
Weighted-average remaining term | 3 years | |||||||
Weighted-average discount rate | [3] | 3.50% | ||||||
Office and Warehouse Space [Member] | ||||||||
Operating Leases [Abstract] | ||||||||
ROU asset carrying value | [1] | $ 170.5 | ||||||
Lease liability carrying value | [2] | $ 184.3 | ||||||
Weighted-average remaining term | 16 years | |||||||
Weighted-average discount rate | [3] | 3.20% | ||||||
|
Commitments and Contingent Liabilities, Consolidated Lease Expense (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Consolidated Lease Expense [Abstract] | |||
Non-cash lease expense (amortization of ROU assets) | $ 39.0 | $ 42.8 | $ 0.0 |
Related accretion expense on lease liability balances | 13.0 | 9.0 | |
Total fixed lease expense | 52.0 | 51.8 | |
Variable lease expense | 0.2 | 6.2 | |
Subtotal operating lease expense | 52.2 | 58.0 | |
Short-term operating leases | 49.8 | 48.6 | |
Total operating lease expense | 102.0 | 106.6 | $ 86.4 |
Cash payments for operating lease liabilities | 37.1 | 48.1 | |
Operating lease income | $ 11.4 | $ 14.4 |
Commitments and Contingent Liabilities, Liquidity Option Agreement (Details) $ in Millions |
2 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Mar. 05, 2020
USD ($)
|
Dec. 31, 2020
USD ($)
|
Dec. 31, 2019
USD ($)
|
Dec. 31, 2018
USD ($)
|
|
Liquidity Option Agreement [Abstract] | ||||
Change in fair value of Liquidity Option Agreement | $ 2.3 | $ 2.3 | $ 119.6 | $ 56.1 |
Level 3 [Member] | Liquidity Option Agreement [Member] | ||||
Liquidity Option Agreement [Abstract] | ||||
Derivative Liability | $ 511.9 | $ 509.6 | ||
Level 3 [Member] | Liquidity Option Agreement [Member] | Minimum [Member] | ||||
Liquidity Option Agreement [Abstract] | ||||
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization | 0.70% | 0.70% | ||
Fair value inputs, OTA ownership interest in Enterprise common units | 2.30% | 2.30% | ||
Level 3 [Member] | Liquidity Option Agreement [Member] | Maximum [Member] | ||||
Liquidity Option Agreement [Abstract] | ||||
Fair value inputs, Expected life of OTA following option exercise | 30 years | 30 years | ||
Fair value inputs, Estimated growth rates in Enterprise earnings before interest, taxes, depreciation and amortization | 2.20% | 2.20% | ||
Fair value inputs, OTA ownership interest in Enterprise common units | 2.50% | 2.50% | ||
Level 3 [Member] | Liquidity Option Agreement [Member] | Measurement Input, Aggregate Tax Rate [Member] | ||||
Liquidity Option Agreement [Abstract] | ||||
Derivative Liability, Measurement Input | 0.228 | 0.228 | ||
Level 3 [Member] | Liquidity Option Agreement [Member] | Measurement input, discount rate [Member] | ||||
Liquidity Option Agreement [Abstract] | ||||
Derivative Liability, Measurement Input | 0.057 | 0.057 |
Significant Risks and Uncertainties (Details) $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2020
USD ($)
| |
Insurance Matters [Abstract] | |
Insurance deductible per incident | $ 30 |
Minimum business interruption period | 60 days |
Named windstorm insurance coverage | $ 200 |
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions |
12 Months Ended | ||||
---|---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|||
Decrease (increase) in: | |||||
Accounts receivable - trade | $ 300.2 | $ (1,248.8) | $ 730.2 | ||
Accounts receivable - related parties | (0.8) | 0.9 | (2.3) | ||
Inventories | (1,420.4) | (558.0) | 121.4 | ||
Prepaid and other current assets | 991.4 | (69.6) | 214.4 | ||
Other assets | (79.6) | (63.5) | (9.7) | ||
Increase (decrease) in: | |||||
Accounts payable - trade | 11.3 | (43.9) | 18.3 | ||
Accounts payable - related parties | (12.8) | 67.8 | 51.4 | ||
Accrued product payables | 482.7 | 1,447.8 | (1,132.0) | ||
Accrued interest | 23.9 | 36.1 | 37.6 | ||
Other current liabilities | (992.1) | 58.1 | (70.9) | ||
Other liabilities | (71.3) | (84.3) | 57.8 | ||
Net effect of changes in operating accounts | (767.5) | (457.4) | 16.2 | ||
Cash payments for interest, net of $115.0, $143.8 and $147.9 capitalized in 2020, 2019 and 2018, respectively | 1,201.3 | 1,080.3 | 1,017.9 | ||
Capitalized interest | [1] | 115.0 | 143.8 | 147.9 | |
Cash payments for federal and state income taxes | 25.1 | 23.6 | 15.5 | ||
Liability for construction in progress expenditures | 236.1 | 432.0 | 567.6 | ||
Sale of Assets: | |||||
Proceeds from asset sales | 12.8 | 20.6 | 161.2 | ||
Net gains attributable to asset sales | 4.4 | 5.7 | 28.7 | ||
Crude Oil Pipeline System [Member] | |||||
Sale of Assets: | |||||
Proceeds from asset sales | 0.0 | 0.0 | 134.9 | ||
Net gains attributable to asset sales | 0.0 | 0.0 | 20.6 | ||
Other Disposal of Assets [Member] | |||||
Sale of Assets: | |||||
Proceeds from asset sales | 12.8 | 20.6 | 26.3 | ||
Net gains attributable to asset sales | $ 4.4 | $ 5.7 | $ 8.1 | ||
|
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