Delaware
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76-0568219
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(State or Other Jurisdiction of Incorporation or Organization)
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(I.R.S. Employer Identification No.)
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1100 Louisiana Street, 10th Floor, Houston, Texas 77002
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(Address of Principal Executive Offices, including Zip Code)
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(713) 381-6500
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(Registrant’s Telephone Number, including Area Code)
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Title of Each Class
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Trading Symbol(s)
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Name of Each Exchange On Which Registered
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Common Units
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EPD
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New York Stock Exchange
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Page
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Number
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||
/d
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=
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per day
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MMBbls
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=
|
million barrels
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BBtus
|
=
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billion British thermal units
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MMBPD
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=
|
million barrels per day
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Bcf
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=
|
billion cubic feet
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MMBtus
|
=
|
million British thermal units
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BPD
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=
|
barrels per day
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MMcf
|
=
|
million cubic feet
|
MBPD
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=
|
thousand barrels per day
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TBtus
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=
|
trillion British thermal units
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• |
natural gas gathering, treating, processing, transportation and storage;
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• |
NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane);
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• |
crude oil gathering, transportation, storage, and marine terminals;
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• |
propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;
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• |
petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”); and
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• |
a marine transportation business that operates on key U.S. inland and intracoastal waterway systems.
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• |
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;
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• |
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;
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• |
enhance the stability of our cash flows by investing in pipelines and other fee-based businesses; and
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• |
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.
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• |
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.
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• |
Propane is used for heating, as an engine and industrial fuel, and as a petrochemical feedstock in the production of ethylene and propylene.
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• |
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.
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• |
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.
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• |
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.
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Total Gas
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||||
Net Gas
|
Processing
|
||||
Production
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Processing
|
Capacity
|
|||
Region
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Ownership
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Capacity
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of Plant
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Facility Name
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Location
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Served
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Interest
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(MMcf/d) (1)
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(MMcf/d)
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Meeker
|
Colorado
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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
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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
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100.0%
|
280
|
280
|
Armstrong
|
Texas
|
Eagle Ford
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100.0%
|
250
|
250
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Gilmore
|
Texas
|
Frio-Vicksburg
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100.0%
|
250
|
250
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San Martin
|
Texas
|
Eagle Ford
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100.0%
|
200
|
200
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South Eddy
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New Mexico
|
Delaware
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100.0%
|
200
|
200
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Waha
|
Texas
|
Delaware
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100.0%
|
150
|
150
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Sonora
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Texas
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Strawn
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100.0%
|
120
|
120
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Venice
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Louisiana
|
Gulf of Mexico
|
13.1% (5)
|
98
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750
|
Indian Springs
|
Texas
|
Wilcox-Woodbine
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75.0% (3)
|
90
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120
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Chaparral
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New Mexico
|
Delaware
|
100.0%
|
45
|
45
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Total
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9,615
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11,065
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(1)
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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.
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(2)
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We own a 75% consolidated interest in the Pascagoula facility through our majority owned subsidiary, Pascagoula Gas Processing LLC.
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(3)
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We proportionately consolidate our undivided interests in these operating assets.
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(4)
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The Carthage processing complex consists of two natural gas processing plants: Panola and Bulldog.
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(5)
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Our 13.1% ownership in the Venice plant is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C.
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Pipeline
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Ownership
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Length
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Description of Asset
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Location(s)
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Interest
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(Miles)
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Mid-America Pipeline System (1)
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Midwest and Western U.S.
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100.0%
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7,977
|
South Texas NGL Pipeline System
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Texas
|
100.0%
|
2,019
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Dixie Pipeline (1)
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South and Southeastern U.S.
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100.0%
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1,307
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ATEX (1)
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Texas to Midwest and Northeast U.S.
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100.0%
|
1,192
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Chaparral NGL System (1)
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Texas, New Mexico
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100.0%
|
1,085
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Louisiana Pipeline System (1)
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Louisiana
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100.0%
|
877
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Seminole NGL Pipeline (1)
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Texas
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100.0%
|
869
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Shin Oak NGL Pipeline
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Texas
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67.0% (3)
|
664
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Texas Express Pipeline (1)
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Texas
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35.0% (4)
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594
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Skelly-Belvieu Pipeline (1)
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Texas, Oklahoma
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50.0% (5)
|
572
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Front Range Pipeline (1)
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Colorado, Oklahoma, Texas
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33.3% (6)
|
451
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Houston Ship Channel Pipeline System
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Texas
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100.0%
|
304
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Aegis Ethane Pipeline (1)
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Texas, Louisiana
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100.0%
|
299
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Panola Pipeline (1)
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Texas
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55.0% (7)
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253
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Rio Grande Pipeline (1)
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Texas
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100.0%
|
249
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Lou-Tex NGL Pipeline (1)
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Texas, Louisiana
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100.0%
|
206
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Promix NGL Gathering System
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Louisiana
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50.0% (8)
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194
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Texas Express Gathering System
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Texas
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45.0% (9)
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170
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Tri-States NGL Pipeline (1)
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Alabama, Mississippi, Louisiana
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83.3% (10)
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168
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Others (eight systems) (2)
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Various
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Various (11)
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459
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Total
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19,909
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(1)
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Interstate transportation services provided by these liquids pipelines, in whole or part, are regulated by federal governmental agencies.
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(2)
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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.
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(3)
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We own a 67% consolidated interest in the Shin Oak NGL Pipeline through our majority owned subsidiary, Breviloba, LLC.
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(4)
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Our 35% ownership interest in the Texas Express Pipeline is held indirectly through our equity method investment in Texas Express Pipeline LLC.
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(5)
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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.
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(6)
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Our 33.3% ownership interest in the Front Range Pipeline is held indirectly through our equity method investment in Front Range Pipeline LLC.
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(7)
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We own a 55% consolidated interest in the Panola Pipeline through our majority owned subsidiary, Panola Pipeline Company, LLC.
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(8)
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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.
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(9)
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Our 45% ownership interest in the Texas Express Gathering System is held indirectly through our equity method investment in Texas Express Gathering LLC.
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(10)
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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.
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(11)
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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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
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.
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• |
The Lou-Tex NGL Pipeline transports mixed NGLs, purity NGL products and refinery grade propylene (“RGP”) between the Louisiana and Texas markets.
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|
Net Plant
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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
|
$
|
1,059.9
|
$
|
334.7
|
||||
Restricted cash
|
98.2
|
75.3
|
||||||
Accounts receivable – trade, net of allowance for doubtful accounts
of $46.5 at December 31, 2020 and $12.4 at December 31, 2019
|
4,802.6
|
4,873.6
|
||||||
Accounts receivable – related parties
|
5.6
|
2.5
|
||||||
Inventories
|
3,303.5
|
2,091.4
|
||||||
Derivative assets (see Note 14)
|
228.6
|
127.2
|
||||||
Prepaid and other current assets
|
411.0
|
358.2
|
||||||
Total current assets
|
9,909.4
|
7,862.9
|
||||||
Property, plant and equipment, net
|
41,912.8
|
41,603.4
|
||||||
Investments in unconsolidated affiliates
|
2,429.2
|
2,600.2
|
||||||
Intangible assets, net of accumulated amortization of $1,826.7 at
December 31, 2020 and $1,687.5 at December 31, 2019 (see Note 6)
|
3,309.1
|
3,449.0
|
||||||
Goodwill (see Note 6)
|
5,448.9
|
5,745.2
|
||||||
Other assets
|
1,097.3
|
472.5
|
||||||
Total assets
|
$
|
64,106.7
|
$
|
61,733.2
|
||||
|
||||||||
LIABILITIES AND EQUITY
|
||||||||
Current liabilities:
|
||||||||
Current maturities of debt (see Note 7)
|
$
|
1,325.0
|
$
|
1,981.9
|
||||
Accounts payable – trade
|
704.6
|
1,004.5
|
||||||
Accounts payable – related parties
|
149.5
|
162.3
|
||||||
Accrued product payables
|
5,395.4
|
4,915.7
|
||||||
Accrued interest
|
455.6
|
431.7
|
||||||
Derivative liabilities (see Note 14)
|
349.2
|
122.4
|
||||||
Other current liabilities
|
608.7
|
511.2
|
||||||
Total current liabilities
|
8,988.0
|
9,129.7
|
||||||
Long-term debt (see Note 7)
|
28,540.7
|
25,643.2
|
||||||
Deferred tax liabilities (see Note 16)
|
464.7
|
100.4
|
||||||
Other long-term liabilities
|
686.6
|
1,032.4
|
||||||
Commitments and contingent liabilities (see Note 17)
|
|
|
||||||
Redeemable preferred limited partner interests: (see Note 8)
|
||||||||
Series A cumulative convertible preferred units (“preferred units”)
(50,138 units outstanding at December 31, 2020)
|
49.3
|
–
|
||||||
Equity: (see Note 8)
|
||||||||
Partners’ equity:
|
||||||||
Common limited partner interests (2,182,308,958 units issued and outstanding at December 31, 2020 and 2,189,226,130 units issued and outstanding at December 31, 2019)
|
25,766.6
|
24,692.6
|
||||||
Treasury units, at cost
|
(1,297.3
|
)
|
–
|
|||||
Accumulated other comprehensive income (loss)
|
(165.2
|
)
|
71.4
|
|||||
Total partners’ equity
|
24,304.1
|
24,764.0
|
||||||
Noncontrolling interests in consolidated subsidiaries
|
1,073.3
|
1,063.5
|
||||||
Total equity
|
25,377.4
|
25,827.5
|
||||||
Total liabilities, preferred units, and equity
|
$
|
64,106.7
|
$
|
61,733.2
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Revenues:
|
||||||||||||
Third parties
|
$
|
27,163.0
|
$
|
32,721.9
|
$
|
36,426.5
|
||||||
Related parties
|
36.7
|
67.3
|
107.7
|
|||||||||
Total revenues (see Note 9)
|
27,199.7
|
32,789.2
|
36,534.2
|
|||||||||
Costs and expenses:
|
||||||||||||
Operating costs and expenses:
|
||||||||||||
Third party and other costs
|
21,160.5
|
25,649.8
|
29,991.2
|
|||||||||
Related parties
|
1,210.6
|
1,412.0
|
1,406.1
|
|||||||||
Total operating costs and expenses
|
22,371.1
|
27,061.8
|
31,397.3
|
|||||||||
General and administrative costs:
|
||||||||||||
Third party and other costs
|
83.4
|
75.3
|
77.4
|
|||||||||
Related parties
|
136.2
|
136.4
|
130.9
|
|||||||||
Total general and administrative costs
|
219.6
|
211.7
|
208.3
|
|||||||||
Total costs and expenses (see Note 10)
|
22,590.7
|
27,273.5
|
31,605.6
|
|||||||||
Equity in income of unconsolidated affiliates
|
426.1
|
563.0
|
480.0
|
|||||||||
Operating income
|
5,035.1
|
6,078.7
|
5,408.6
|
|||||||||
Other income (expense):
|
||||||||||||
Interest expense
|
(1,287.4
|
)
|
(1,243.0
|
)
|
(1,096.7
|
)
|
||||||
Change in fair market value of Liquidity Option (see Note 17)
|
(2.3
|
)
|
(119.6
|
)
|
(56.1
|
)
|
||||||
Gain on step acquisition of unconsolidated affiliate (see Note 12)
|
–
|
–
|
39.4
|
|||||||||
Interest income
|
13.4
|
11.6
|
3.6
|
|||||||||
Other, net
|
2.6
|
5.0
|
–
|
|||||||||
Total other expense, net
|
(1,273.7
|
)
|
(1,346.0
|
)
|
(1,109.8
|
)
|
||||||
Income before income taxes
|
3,761.4
|
4,732.7
|
4,298.8
|
|||||||||
Benefit from (provision for) income taxes (see Note 16)
|
124.3
|
(45.6
|
)
|
(60.3
|
)
|
|||||||
Net income
|
3,885.7
|
4,687.1
|
4,238.5
|
|||||||||
Net income attributable to noncontrolling interests (see Note 8)
|
(110.1
|
)
|
(95.8
|
)
|
(66.1
|
)
|
||||||
Net income attributable to preferred units (see Note 8)
|
(0.9
|
)
|
–
|
–
|
||||||||
Net income attributable to common unitholders
|
$
|
3,774.7
|
$
|
4,591.3
|
$
|
4,172.4
|
||||||
|
||||||||||||
Earnings per unit: (see Note 11)
|
||||||||||||
Basic earnings per common unit
|
$
|
1.71
|
$
|
2.09
|
$
|
1.91
|
||||||
Diluted earnings per common unit
|
$
|
1.71
|
$
|
2.09
|
$
|
1.91
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Net income
|
$
|
3,885.7
|
$
|
4,687.1
|
$
|
4,238.5
|
||||||
Other comprehensive income (loss):
|
||||||||||||
Cash flow hedges: (see Note 14)
|
||||||||||||
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 (see Note 8)
|
(0.9
|
)
|
–
|
–
|
||||||||
Comprehensive income attributable to common unitholders
|
$
|
3,538.1
|
$
|
4,611.8
|
$
|
4,395.0
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Operating activities:
|
||||||||||||
Net income
|
$
|
3,885.7
|
$
|
4,687.1
|
$
|
4,238.5
|
||||||
Reconciliation of net income to net cash flows provided by operating activities:
|
||||||||||||
Depreciation, amortization and accretion
|
2,071.9
|
1,949.3
|
1,791.6
|
|||||||||
Impairment of goodwill (see Notes 2 and 6)
|
296.3
|
–
|
–
|
|||||||||
Impairment of assets other than goodwill (see Notes 2 and 4)
|
594.3
|
132.8
|
50.5
|
|||||||||
Equity in income of unconsolidated affiliates
|
(426.1
|
)
|
(563.0
|
)
|
(480.0
|
)
|
||||||
Distributions received from unconsolidated affiliates attributable to earnings
|
426.6
|
568.0
|
479.4
|
|||||||||
Net gains attributable to asset sales (see Note 19)
|
(4.4
|
)
|
(5.7
|
)
|
(28.7
|
)
|
||||||
Deferred income tax expense (benefit)
|
(147.6
|
)
|
20.0
|
21.4
|
||||||||
Change in fair market value of derivative instruments
|
(79.3
|
)
|
27.2
|
17.8
|
||||||||
Change in fair market value of Liquidity Option (see Note 17)
|
2.3
|
119.6
|
56.1
|
|||||||||
Gain on step acquisition of unconsolidated affiliate (see Note 12)
|
–
|
–
|
(39.4
|
)
|
||||||||
Non-cash expense related to long-term operating leases (see Note 17)
|
39.0
|
42.8
|
–
|
|||||||||
Net effect of changes in operating accounts (see Note 19)
|
(767.5
|
)
|
(457.4
|
)
|
16.2
|
|||||||
Other operating activities
|
0.3
|
(0.2
|
)
|
2.9
|
||||||||
Net cash flows provided by operating activities
|
5,891.5
|
6,520.5
|
6,126.3
|
|||||||||
Investing activities:
|
||||||||||||
Capital expenditures
|
(3,287.9
|
)
|
(4,531.7
|
)
|
(4,223.2
|
)
|
||||||
Cash used for business combinations, net of cash received (see Note 12)
|
–
|
–
|
(150.6
|
)
|
||||||||
Investments in unconsolidated affiliates
|
(15.6
|
)
|
(111.6
|
)
|
(113.6
|
)
|
||||||
Distributions received from unconsolidated affiliates attributable to the return of capital
|
187.5
|
63.3
|
50.0
|
|||||||||
Proceeds from asset sales (see Note 19)
|
12.8
|
20.6
|
161.2
|
|||||||||
Other investing activities
|
(17.5
|
)
|
(16.1
|
)
|
(5.4
|
)
|
||||||
Cash used in investing activities
|
(3,120.7
|
)
|
(4,575.5
|
)
|
(4,281.6
|
)
|
||||||
Financing activities:
|
||||||||||||
Borrowings under debt agreements
|
6,672.1
|
58,172.6
|
79,588.7
|
|||||||||
Repayments of debt
|
(4,406.6
|
)
|
(56,716.5
|
)
|
(77,957.1
|
)
|
||||||
Debt issuance costs
|
(46.3
|
)
|
(27.6
|
)
|
(49.1
|
)
|
||||||
Monetization of interest rate derivative instruments (see Note 14)
|
(33.3
|
)
|
–
|
22.1
|
||||||||
Cash distributions paid to common unitholders (see Note 8)
|
(3,891.0
|
)
|
(3,839.8
|
)
|
(3,726.9
|
)
|
||||||
Cash payments made in connection with distribution equivalent rights
|
(27.1
|
)
|
(22.1
|
)
|
(17.7
|
)
|
||||||
Cash distributions paid to noncontrolling interests (see Note 8)
|
(131.3
|
)
|
(106.2
|
)
|
(81.6
|
)
|
||||||
Cash contributions from noncontrolling interests (see Note 8)
|
30.9
|
632.8
|
238.1
|
|||||||||
Net cash proceeds from the issuance of common units
|
–
|
82.2
|
538.4
|
|||||||||
Repurchase of common units under buyback programs (see Note 8)
|
(186.3
|
)
|
(81.1
|
)
|
(30.8
|
)
|
||||||
Net cash proceeds from the issuance of preferred units (see Note 8)
|
31.5
|
–
|
–
|
|||||||||
Other financing activities
|
(35.3
|
)
|
(39.4
|
)
|
(29.0
|
)
|
||||||
Cash used in financing activities
|
(2,022.7
|
)
|
(1,945.1
|
)
|
(1,504.9
|
)
|
||||||
Net change in cash and cash equivalents, including restricted cash
|
748.1
|
(0.1
|
)
|
339.8
|
||||||||
Cash and cash equivalents, including restricted cash, January 1
|
410.0
|
410.1
|
70.3
|
|||||||||
Cash and cash equivalents, including restricted cash, December 31
|
$
|
1,158.1
|
$
|
410.0
|
$
|
410.1
|
|
Partners’ Equity
|
|||||||||||||||||||
|
Common
Limited
Partner
Interests
|
Treasury
Units
|
Accumulated
Other
Comprehensive
Income (Loss)
|
Noncontrolling
Interests in
Consolidated
Subsidiaries
|
Total
|
|||||||||||||||
Balance, December 31, 2017
|
$
|
22,718.9
|
$
|
–
|
$
|
(171.7
|
)
|
$
|
225.2
|
$
|
22,772.4
|
|||||||||
Net income
|
4,172.4
|
–
|
–
|
66.1
|
4,238.5
|
|||||||||||||||
Cash distributions paid to common unitholders
|
(3,726.9
|
)
|
–
|
–
|
–
|
(3,726.9
|
)
|
|||||||||||||
Cash payments made in connection with distribution
equivalent rights
|
(17.7
|
)
|
–
|
–
|
–
|
(17.7
|
)
|
|||||||||||||
Cash distributions paid to noncontrolling interests
|
–
|
–
|
–
|
(81.6
|
)
|
(81.6
|
)
|
|||||||||||||
Cash contributions from noncontrolling interests
|
–
|
–
|
–
|
238.1
|
238.1
|
|||||||||||||||
Net cash proceeds from the issuance of common units
|
538.4
|
–
|
–
|
–
|
538.4
|
|||||||||||||||
Common units issued in connection with employee compensation
|
39.1
|
–
|
–
|
–
|
39.1
|
|||||||||||||||
Common units issued in connection with land acquisition
|
30.0
|
–
|
–
|
–
|
30.0
|
|||||||||||||||
Repurchase and cancellation of common units under
Legacy Buyback Program
|
(30.8
|
)
|
–
|
–
|
–
|
(30.8
|
)
|
|||||||||||||
Amortization of fair value of equity-based awards
|
104.7
|
–
|
–
|
–
|
104.7
|
|||||||||||||||
Cash flow hedges
|
–
|
–
|
223.1
|
–
|
223.1
|
|||||||||||||||
Other, net
|
(25.5
|
)
|
–
|
(0.5
|
)
|
(9.1
|
)
|
(35.1
|
)
|
|||||||||||
Balance, December 31, 2018
|
23,802.6
|
–
|
50.9
|
438.7
|
24,292.2
|
|||||||||||||||
Net income
|
4,591.3
|
–
|
–
|
95.8
|
4,687.1
|
|||||||||||||||
Cash distributions paid to common unitholders
|
(3,839.8
|
)
|
–
|
–
|
–
|
(3,839.8
|
)
|
|||||||||||||
Cash payments made in connection with distribution
equivalent rights
|
(22.1
|
)
|
–
|
–
|
–
|
(22.1
|
)
|
|||||||||||||
Cash distributions paid to noncontrolling interests
|
–
|
–
|
–
|
(106.2
|
)
|
(106.2
|
)
|
|||||||||||||
Cash contributions from noncontrolling interests
|
–
|
–
|
–
|
632.8
|
632.8
|
|||||||||||||||
Net cash proceeds from the issuance of common units
|
82.2
|
–
|
–
|
–
|
82.2
|
|||||||||||||||
Common units issued in connection with employee compensation
|
45.6
|
–
|
–
|
–
|
45.6
|
|||||||||||||||
Repurchase and cancellation of common units under
2019 Buyback Program
|
(81.1
|
)
|
–
|
–
|
–
|
(81.1
|
)
|
|||||||||||||
Amortization of fair value of equity-based awards
|
143.3
|
–
|
–
|
–
|
143.3
|
|||||||||||||||
Cash flow hedges
|
–
|
–
|
21.1
|
–
|
21.1
|
|||||||||||||||
Other, net
|
(29.4
|
)
|
–
|
(0.6
|
)
|
2.4
|
(27.6
|
)
|
||||||||||||
Balance, December 31, 2019
|
24,692.6
|
–
|
71.4
|
1,063.5
|
25,827.5
|
|||||||||||||||
Net income
|
3,774.7
|
–
|
–
|
110.1
|
3,884.8
|
|||||||||||||||
Cash distributions paid to common unitholders
|
(3,891.0
|
)
|
–
|
–
|
–
|
(3,891.0
|
)
|
|||||||||||||
Cash payments made in connection with distribution
equivalent rights
|
(27.1
|
)
|
–
|
–
|
–
|
(27.1
|
)
|
|||||||||||||
Cash distributions paid to noncontrolling interests
|
–
|
–
|
–
|
(131.3
|
)
|
(131.3
|
)
|
|||||||||||||
Cash contributions from noncontrolling interests
|
–
|
–
|
–
|
30.9
|
30.9
|
|||||||||||||||
Repurchase and cancellation of common units under
2019 Buyback Program
|
(186.3
|
)
|
–
|
–
|
–
|
(186.3
|
)
|
|||||||||||||
Common units issued to Skyline North Americas, Inc. in
connection with settlement of Liquidity Option (see Note 8)
|
1,297.3
|
–
|
–
|
–
|
1,297.3
|
|||||||||||||||
Treasury units acquired in connection with settlement
of Liquidity Option, at cost (see Note 8)
|
–
|
(1,297.3
|
)
|
–
|
–
|
(1,297.3
|
)
|
|||||||||||||
Common units exchanged for preferred units, with common units received being immediately cancelled (see Note 8)
|
(17.5
|
)
|
–
|
–
|
–
|
(17.5
|
)
|
|||||||||||||
Amortization of fair value of equity-based awards
|
158.6
|
–
|
–
|
–
|
158.6
|
|||||||||||||||
Cash flow hedges
|
–
|
–
|
(236.5
|
)
|
–
|
(236.5
|
)
|
|||||||||||||
Other, net
|
(34.7
|
)
|
–
|
(0.1
|
)
|
0.1
|
(34.7
|
)
|
||||||||||||
Balance, December 31, 2020
|
$
|
25,766.6
|
$
|
(1,297.3
|
)
|
$
|
(165.2
|
)
|
$
|
1,073.3
|
$
|
25,377.4
|
•
|
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
|
$
|
12.4
|
$
|
11.5
|
$
|
12.1
|
||||||
Charged to costs and expenses
|
8.4
|
1.2
|
0.7
|
|||||||||
Charged to other accounts (1)
|
28.7
|
–
|
–
|
|||||||||
Deductions
|
(3.0
|
)
|
(0.3
|
)
|
(1.3
|
)
|
||||||
Balance at end of period
|
$
|
46.5
|
$
|
12.4
|
$
|
11.5
|
(1)
|
Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for doubtful accounts in connection with customer bankruptcies and contractual disputes.
|
|
December 31,
|
|||||||
|
2020
|
2019
|
||||||
Cash and cash equivalents
|
$
|
1,059.9
|
$
|
334.7
|
||||
Restricted cash
|
98.2
|
75.3
|
||||||
Total cash, cash equivalents and restricted cash shown in the
Statements of Consolidated Cash Flows
|
$
|
1,158.1
|
$
|
410.0
|
• |
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
|
$
|
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
|
• |
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)
|
$
|
589.8
|
$
|
51.0
|
$
|
46.8
|
||||||
Investment in unconsolidated affiliate (see Note 5)
|
–
|
76.4
|
–
|
|||||||||
Goodwill (see Note 6)
|
296.3
|
–
|
–
|
|||||||||
Other (1)
|
4.5
|
5.3
|
3.7
|
|||||||||
Total asset impairment charges in operating costs and expenses
|
890.6
|
132.7
|
50.5
|
|||||||||
Other property, plant and equipment impairment charges (2)
|
–
|
0.1
|
–
|
|||||||||
Total asset impairment charges
|
$
|
890.6
|
$
|
132.8
|
$
|
50.5
|
(1)
|
Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill.
|
(2)
|
Amounts presented are reflected in general and administrative costs.
|
• |
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
|
$
|
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
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
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
|
(1)
|
Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
|
|
Estimated
Useful Life
|
December 31,
|
||||||||||
|
in Years
|
2020
|
2019
|
|||||||||
Plants, pipelines and facilities (1)
|
3-45
|
(5)
|
$
|
49,972.8
|
$
|
47,201.2
|
||||||
Underground and other storage facilities (2)
|
5-40
|
(6)
|
4,207.5
|
3,965.5
|
||||||||
Transportation equipment (3)
|
3-10
|
204.9
|
198.9
|
|||||||||
Marine vessels (4)
|
15-30
|
932.7
|
905.9
|
|||||||||
Land
|
371.9
|
372.3
|
||||||||||
Construction in progress
|
1,807.7
|
2,641.2
|
||||||||||
Total
|
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
|
(1)
|
Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets.
|
(2)
|
Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets.
|
(3)
|
Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
|
(4)
|
Marine vessels include tow boats, barges and related equipment used in our marine transportation business.
|
(5)
|
In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years.
|
(6)
|
In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Depreciation expense (1)
|
$
|
1,681.9
|
$
|
1,562.6
|
$
|
1,436.2
|
||||||
Capitalized interest (2)
|
115.0
|
143.8
|
147.9
|
(1)
|
Depreciation expense is a component of “Costs and expenses” as presented on our Statements of Consolidated Operations.
|
(2)
|
Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations.
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
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
|
2021
|
2022
|
2023
|
2024
|
2025
|
||||||||||||||
$
|
8.6
|
$
|
9.1
|
$
|
9.6
|
$
|
10.3
|
$
|
10.9
|
For the Year Ended December 31,
|
||||||||||||
2020
|
2019
|
2018
|
||||||||||
NGL Pipelines & Services:
|
||||||||||||
South Texas natural gas processing plants
|
$
|
86.9
|
$
|
15.6
|
||||||||
Other
|
121.2
|
23.5
|
$
|
18.6
|
||||||||
Crude Oil Pipelines & Services:
|
||||||||||||
Cancellation of Midland-to-ECHO 4 project
|
42.2
|
|||||||||||
Other
|
3.3
|
2.6
|
11.2
|
|||||||||
Natural Gas Pipelines & Services:
|
||||||||||||
South Texas natural gas gathering pipelines
|
37.8
|
|||||||||||
Other
|
5.5
|
4.8
|
13.9
|
|||||||||
Petrochemical & Refined Products Services:
|
||||||||||||
Marine transportation business
|
252.1
|
|||||||||||
Other
|
40.8
|
4.6
|
3.1
|
|||||||||
Total impairment charges for property, plant and equipment
|
$
|
589.8
|
$
|
51.1
|
$
|
46.8
|
• |
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 $256.7 million, which reduced the carrying value of this asset group to its estimated fair value of $410.0 million at December 31, 2020. The impairment charge reduced property, plant and equipment by $252.1 million and intangible assets by $4.6 million. Our marine transportation assets, which consist of 65 tow boats, 160 tank barges and shipyard and repair facilities, serve refinery and storage terminal customers along the Mississippi River, the intracoastal waterway between Texas and Florida, and the Tennessee-Tombigbee waterway system.
|
• |
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 $125.7 million, which reduced the total carrying value of these assets to their estimated fair value of $21.3 million at December 31, 2020. The impairment charge reduced property, plant and equipment by $124.7 million and intangible assets by $1.0 million. The natural gas assets impacted by this review were our Armstrong, Gilmore, Shilling and Indian Springs natural gas processing facilities and our Indian Springs and Big Thicket Gathering Systems.
|
• |
In September 2020, we recognized $42.2 million of impairment expense due to our cancellation of the Midland-to-ECHO 4 pipeline construction project. In connection with the cancellation, we reclassified $311.7 million of pipe and related items that were purchased for the project from construction in progress to long-term spare parts, where they will be held for future use. Long-term spare parts is a component of “Other assets” as presented on our Consolidated Balance Sheet. While being held as long-term spare parts, these assets are depreciated over their expected useful lives as spare parts.
|
• |
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”)
|
13.1%
|
|
$
|
23.4
|
|
$
|
23.2
|
K/D/S Promix, L.L.C. (“Promix”)
|
50%
|
|
|
23.0
|
|
|
25.7
|
Baton Rouge Fractionators LLC (“BRF”)
|
32.2%
|
|
|
13.8
|
|
|
15.6
|
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)
|
50%
|
|
|
31.6
|
|
|
33.1
|
Texas Express Pipeline LLC (“Texas Express”)
|
35%
|
|
|
342.8
|
|
|
358.1
|
Texas Express Gathering LLC (“TEG”)
|
45%
|
|
|
37.7
|
|
|
41.1
|
Front Range Pipeline LLC (“Front Range”)
|
33.3%
|
|
|
199.3
|
|
|
207.0
|
Crude Oil Pipelines & Services:
|
|
|
|
|
|
|
|
Seaway Crude Holdings LLC (“Seaway”)
|
50%
|
|
|
1,224.0
|
|
|
1,353.1
|
Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”)
|
50%
|
|
|
376.8
|
|
|
386.5
|
Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”)
|
50%
|
122.9
|
126.9
|
||||
Natural Gas Pipelines & Services:
|
|
|
|
|
|
|
|
White River Hub, LLC (“White River Hub”)
|
50%
|
|
|
18.2
|
|
|
19.1
|
Old Ocean Pipeline, LLC (“Old Ocean”)
|
50%
|
13.2
|
8.2
|
||||
Petrochemical & Refined Products Services:
|
|
|
|
||||
Baton Rouge Propylene Concentrator LLC (“BRPC”)
|
30%
|
1.6
|
2.0
|
||||
Transport 4, LLC (“Transport 4”)
|
25%
|
|
|
0.9
|
0.6
|
||
Total
|
$
|
2,429.2
|
$
|
2,600.2
|
• |
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
|
$
|
121.3
|
$
|
114.5
|
$
|
117.0
|
||||||
Crude Oil Pipelines & Services
|
301.2
|
449.2
|
365.4
|
|||||||||
Natural Gas Pipelines & Services
|
5.8
|
6.3
|
6.8
|
|||||||||
Petrochemical & Refined Products Services (1)
|
(2.2
|
)
|
(7.0
|
)
|
(9.2
|
)
|
||||||
Total
|
$
|
426.1
|
$
|
563.0
|
$
|
480.0
|
(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
|
$
|
447.8
|
$
|
(221.3
|
)
|
$
|
226.5
|
$
|
447.8
|
$
|
(206.3
|
)
|
$
|
241.5
|
||||||||||
Contract-based intangibles
|
162.6
|
(55.0
|
)
|
107.6
|
162.6
|
(43.9
|
)
|
118.7
|
||||||||||||||||
Segment total
|
610.4
|
(276.3
|
)
|
334.1
|
610.4
|
(250.2
|
)
|
360.2
|
||||||||||||||||
Crude Oil Pipelines & Services:
|
||||||||||||||||||||||||
Customer relationship intangibles
|
2,195.0
|
(291.6
|
)
|
1,903.4
|
2,203.5
|
(243.5
|
)
|
1,960.0
|
||||||||||||||||
Contract-based intangibles
|
283.1
|
(249.9
|
)
|
33.2
|
276.9
|
(235.0
|
)
|
41.9
|
||||||||||||||||
Segment total
|
2,478.1
|
(541.5
|
)
|
1,936.6
|
2,480.4
|
(478.5
|
)
|
2,001.9
|
||||||||||||||||
Natural Gas Pipelines & Services:
|
||||||||||||||||||||||||
Customer relationship intangibles
|
1,350.3
|
(512.2
|
)
|
838.1
|
1,350.3
|
(481.6
|
)
|
868.7
|
||||||||||||||||
Contract-based intangibles
|
470.7
|
(403.8
|
)
|
66.9
|
468.0
|
(395.5
|
)
|
72.5
|
||||||||||||||||
Segment total
|
1,821.0
|
(916.0
|
)
|
905.0
|
1,818.3
|
(877.1
|
)
|
941.2
|
||||||||||||||||
Petrochemical & Refined Products Services:
|
||||||||||||||||||||||||
Customer relationship intangibles
|
181.4
|
(68.3
|
)
|
113.1
|
181.4
|
(57.5
|
)
|
123.9
|
||||||||||||||||
Contract-based intangibles
|
44.9
|
(24.6
|
)
|
20.3
|
46.0
|
(24.2
|
)
|
21.8
|
||||||||||||||||
Segment total
|
226.3
|
(92.9
|
)
|
133.4
|
227.4
|
(81.7
|
)
|
145.7
|
||||||||||||||||
Total intangible assets
|
$
|
5,135.8
|
$
|
(1,826.7
|
)
|
$
|
3,309.1
|
$
|
5,136.5
|
$
|
(1,687.5
|
)
|
$
|
3,449.0
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
NGL Pipelines & Services
|
$
|
25.2
|
$
|
31.9
|
$
|
34.7
|
||||||
Crude Oil Pipelines & Services
|
71.5
|
92.7
|
87.8
|
|||||||||
Natural Gas Pipelines & Services
|
38.8
|
41.4
|
39.1
|
|||||||||
Petrochemical & Refined Products Services
|
7.7
|
8.7
|
8.7
|
|||||||||
Total
|
$
|
143.2
|
$
|
174.7
|
$
|
170.3
|
2021
|
2022
|
2023
|
2024
|
2025
|
||||||||||||||
$
|
144.5
|
$
|
161.3
|
$
|
169.0
|
$
|
165.1
|
$
|
163.5
|
a
|
Weighted
Average
Remaining
Amortization
Period
|
December 31, 2020
|
|||||||||
Gross
Value
|
Accumulated
Amortization
|
Carrying
Value
|
|||||||||
Basin-specific customer relationships:
|
|||||||||||
EFS Midstream (acquired 2015)
|
21.4 years
|
$
|
1,409.8
|
$
|
(188.1)
|
$
|
1,221.7
|
||||
State Line and Fairplay (acquired 2010)
|
26.2 years
|
895.0
|
(224.0)
|
671.0
|
|||||||
San Juan Gathering (acquired 2004)
|
18.8 years
|
331.3
|
(245.3)
|
86.0
|
|||||||
General customer relationships:
|
|||||||||||
Oiltanking (acquired 2014)
|
23.0 years
|
1,192.5
|
(162.6)
|
1,029.9
|
• |
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
|
3.0 years
|
$
|
293.3
|
$
|
(261.7)
|
$
|
31.6
|
||||
Jonah natural gas gathering agreements
|
21.0 years
|
224.4
|
(175.8)
|
48.6
|
|||||||
Delaware Basin natural gas processing contracts
|
6.0 years
|
82.6
|
(23.7)
|
58.9
|
• |
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
|
$
|
2,651.7
|
$
|
1,841.0
|
$
|
296.3
|
$
|
956.2
|
$
|
5,745.2
|
||||||||||
Balance at December 31, 2019
|
$
|
2,651.7
|
$
|
1,841.0
|
$
|
296.3
|
$
|
956.2
|
$
|
5,745.2
|
||||||||||
Impairment of goodwill
|
–
|
–
|
(296.3
|
)
|
–
|
(296.3
|
)
|
|||||||||||||
Balance at December 31, 2020
|
$
|
2,651.7
|
$
|
1,841.0
|
$
|
–
|
$
|
956.2
|
$
|
5,448.9
|
|
December 31,
|
|||||||
|
2020
|
2019
|
||||||
EPO senior debt obligations:
|
||||||||
Commercial Paper Notes, variable-rates
|
$
|
–
|
$
|
482.0
|
||||
Senior Notes Q, 5.25% fixed-rate, due January 2020
|
–
|
500.0
|
||||||
Senior Notes Y, 5.20% fixed-rate, due September 2020
|
–
|
1,000.0
|
||||||
Senior Notes TT, 2.80% fixed-rate, due February 2021
|
750.0
|
750.0
|
||||||
Senior Notes RR, 2.85% fixed-rate, due April 2021
|
575.0
|
575.0
|
||||||
September 2020 364-Day Revolving Credit Agreement, variable-rate, due September 2021
|
–
|
–
|
||||||
Senior Notes VV, 3.50% fixed-rate, due February 2022
|
750.0
|
750.0
|
||||||
Senior Notes CC, 4.05% fixed-rate, due February 2022
|
650.0
|
650.0
|
||||||
Senior Notes HH, 3.35% fixed-rate, due March 2023
|
1,250.0
|
1,250.0
|
||||||
Senior Notes JJ, 3.90% fixed-rate, due February 2024
|
850.0
|
850.0
|
||||||
Multi-Year Revolving Credit Agreement, variable-rate, due September 2024
|
–
|
–
|
||||||
Senior Notes MM, 3.75% fixed-rate, due February 2025
|
1,150.0
|
1,150.0
|
||||||
Senior Notes PP, 3.70% fixed-rate, due February 2026
|
875.0
|
875.0
|
||||||
Senior Notes SS, 3.95% fixed-rate, due February 2027
|
575.0
|
575.0
|
||||||
Senior Notes WW, 4.15% fixed-rate, due October 2028
|
1,000.0
|
1,000.0
|
||||||
Senior Notes YY, 3.125% fixed-rate, due July 2029
|
1,250.0
|
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
|
500.0
|
||||||
Senior Notes H, 6.65% fixed-rate, due October 2034
|
350.0
|
350.0
|
||||||
Senior Notes J, 5.75% fixed-rate, due March 2035
|
250.0
|
250.0
|
||||||
Senior Notes W, 7.55% fixed-rate, due April 2038
|
399.6
|
399.6
|
||||||
Senior Notes R, 6.125% fixed-rate, due October 2039
|
600.0
|
600.0
|
||||||
Senior Notes Z, 6.45% fixed-rate, due September 2040
|
600.0
|
600.0
|
||||||
Senior Notes BB, 5.95% fixed-rate, due February 2041
|
750.0
|
750.0
|
||||||
Senior Notes DD, 5.70% fixed-rate, due February 2042
|
600.0
|
600.0
|
||||||
Senior Notes EE, 4.85% fixed-rate, due August 2042
|
750.0
|
750.0
|
||||||
Senior Notes GG, 4.45% fixed-rate, due February 2043
|
1,100.0
|
1,100.0
|
||||||
Senior Notes II, 4.85% fixed-rate, due March 2044
|
1,400.0
|
1,400.0
|
||||||
Senior Notes KK, 5.10% fixed-rate, due February 2045
|
1,150.0
|
1,150.0
|
||||||
Senior Notes QQ, 4.90% fixed-rate, due May 2046
|
975.0
|
975.0
|
||||||
Senior Notes UU, 4.25% fixed-rate, due February 2048
|
1,250.0
|
1,250.0
|
||||||
Senior Notes XX, 4.80% fixed-rate, due February 2049
|
1,250.0
|
1,250.0
|
||||||
Senior Notes ZZ, 4.20% fixed-rate, due January 2050
|
1,250.0
|
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
|
400.0
|
||||||
Senior Notes CCC, 3.95% fixed rate, due January 2060
|
1,000.0
|
–
|
||||||
TEPPCO senior debt obligations:
|
||||||||
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038
|
0.4
|
0.4
|
||||||
Total principal amount of senior debt obligations
|
27,500.0
|
25,232.0
|
||||||
EPO Junior Subordinated Notes C, variable-rate, due June 2067 (1)
|
232.2
|
232.2
|
||||||
EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 (2)
|
700.0
|
700.0
|
||||||
EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 (3)
|
1,000.0
|
1,000.0
|
||||||
EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 (4)
|
700.0
|
700.0
|
||||||
TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 (1)
|
14.2
|
14.2
|
||||||
Total principal amount of senior and junior debt obligations
|
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
|
(1)
|
Variable rate is reset quarterly and based on 3-month London Interbank Offered Rate ("LIBOR") plus 2.778%.
|
(2)
|
Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%.
|
(3)
|
Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.
|
(4)
|
Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%.
|
|
Range of Interest
Rates Paid
|
Weighted-Average
Interest Rate Paid
|
Commercial Paper Notes
|
1.78% to 2.08%
|
1.86%
|
EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes
|
3.00% to 4.68%
|
3.66%
|
|
Scheduled Maturities of Debt
|
|||||||||||||||||||||||||||
|
Total
|
2021
|
2022
|
2023
|
2024
|
2025
|
Thereafter
|
|||||||||||||||||||||
Senior Notes
|
$
|
27,500.0
|
$
|
1,325.0
|
$
|
1,400.0
|
$
|
1,250.0
|
$
|
850.0
|
$
|
1,150.0
|
$
|
21,525.0
|
||||||||||||||
Junior Subordinated Notes
|
2,646.4
|
–
|
–
|
–
|
–
|
–
|
2,646.4
|
|||||||||||||||||||||
Total
|
$
|
30,146.4
|
$
|
1,325.0
|
$
|
1,400.0
|
$
|
1,250.0
|
$
|
850.0
|
$
|
1,150.0
|
$
|
24,171.4
|
Common units outstanding at December 31, 2017
|
2,161,089,479
|
|||
Common unit repurchases under Legacy Buyback Program
|
(1,236,800
|
)
|
||
Common units issued in connection with DRIP and EUPP
|
19,861,951
|
|||
Common units issued in connection with the vesting of phantom unit awards, net
|
2,442,436
|
|||
Common units issued in connection with employee compensation
|
1,443,586
|
|||
Common units issued in connection with land acquisition
|
1,223,242
|
|||
Other
|
45,135
|
|||
Common units outstanding at December 31, 2018
|
2,184,869,029
|
|||
Common unit repurchases under 2019 Buyback Program
|
(2,909,128
|
)
|
||
Common units issued in connection with DRIP and EUPP
|
2,897,990
|
|||
Common units issued in connection with the vesting of phantom unit awards, net
|
2,720,603
|
|||
Common units issued in connection with employee compensation
|
1,626,041
|
|||
Other
|
21,595
|
|||
Common units outstanding at December 31, 2019
|
2,189,226,130
|
|||
Common units issued to Skyline North Americas, Inc. in connection with
settlement of Liquidity Option in March 2020
|
54,807,352
|
|||
Treasury units acquired in connection with settlement of the Liquidity Option in March 2020
|
(54,807,352
|
)
|
||
Common unit repurchases under 2019 Buyback Program
|
(8,978,317
|
)
|
||
Common units issued in connection with the vesting of phantom unit awards, net
|
3,162,095
|
|||
Common units exchanged for preferred units in September 2020,
with the common units received being immediately cancelled
|
(1,120,588
|
)
|
||
Other
|
19,638
|
|||
Common units outstanding at December 31, 2020
|
2,182,308,958
|
Original issuance of preferred units on September 30, 2020:
|
||||
Units sold to third party purchasers
|
35,000
|
|||
Units sold to a related party
|
15,000
|
|||
Total preferred units outstanding at September 30, 2020
|
50,000
|
|||
Paid-in kind distribution to related party
|
138
|
|||
Preferred units outstanding at December 31, 2020
|
50,138
|
•
|
With respect to distribution and liquidation rights, the preferred units rank senior to the Partnership’s common units. Preferred units held by persons other than the Partnership, its subsidiaries and its affiliates generally will vote on an as-converted basis with the Partnership’s common units and have certain class voting rights with respect to certain protective matters.
|
•
|
Holders of the preferred units are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. The Partnership is prohibited from paying distributions on its common units unless full cumulative distributions on the preferred units are paid or set aside for payment. The Partnership may satisfy its obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a holder to elect all cash and other conditions as described in the Partnership Agreement. The exchange by OTA of its common units for PIK-eligible preferred units enables the Partnership to more effectively manage its consolidated cash balances.
|
•
|
Subject to certain limitations, each preferred unitholder may elect to convert its preferred units on or after September 30, 2025 into a number of the Partnership’s common units equal to (a) the number of preferred units to be converted multiplied by (b) the quotient of (i) $1,000 plus any accrued and unpaid distributions per preferred unit, divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). In addition, each preferred unitholder may convert its preferred units into common units if EPO’s senior notes cease to have an investment grade rating or a Change of Control (as defined in the Partnership Agreement) occurs, in each case based on the conversion ratio specified in the Partnership Agreement.
|
•
|
The Partnership may elect to redeem the preferred units for cash, in whole or in part, based on a redemption price outlined in the following schedule, plus any accrued and unpaid distributions at the redemption date:
|
•
|
$1,100 per preferred unit from September 30, 2020 through September 29, 2022;
|
•
|
$1,070 per preferred unit from September 30, 2022 through September 29, 2024;
|
•
|
$1,030 per preferred unit from September 30, 2024 through September 29, 2025;
|
•
|
$1,010 per preferred unit from September 30, 2025 through September 29, 2026; and
|
•
|
$1,000 per preferred unit on or after September 30, 2026; however,
|
•
|
if a Change of Control event occurs prior to September 30, 2026, the redemption price is $1,010 per preferred unit.
|
|
Cash Flow Hedges
|
|||||||||||||||
|
Commodity
Derivative
Instruments
|
Interest Rate
Derivative
Instruments
|
Other
|
Total
|
||||||||||||
Accumulated Other Comprehensive Income (Loss), December 31, 2018
|
$
|
152.7
|
$
|
(104.8
|
)
|
$
|
3.0
|
$
|
50.9
|
|||||||
Other comprehensive income (loss) for period, before reclassifications
|
44.1
|
81.4
|
(0.6
|
)
|
124.9
|
|||||||||||
Reclassification of losses (gains) to net income during period
|
(141.7
|
)
|
37.3
|
–
|
(104.4
|
)
|
||||||||||
Total other comprehensive income (loss) for period
|
(97.6
|
)
|
118.7
|
(0.6
|
)
|
20.5
|
||||||||||
Accumulated Other Comprehensive Income (Loss), December 31, 2019
|
55.1
|
13.9
|
2.4
|
71.4
|
||||||||||||
Other comprehensive income (loss) for period, before reclassifications
|
124.4
|
(127.5
|
)
|
(0.1
|
)
|
(3.2
|
)
|
|||||||||
Reclassification of losses (gains) to net income during period
|
(272.7
|
)
|
39.3
|
–
|
(233.4
|
)
|
||||||||||
Total other comprehensive income (loss) for period
|
(148.3
|
)
|
(88.2
|
)
|
(0.1
|
)
|
(236.6
|
)
|
||||||||
Accumulated Other Comprehensive Income (Loss), December 31, 2020
|
$
|
(93.2
|
)
|
$
|
(74.3
|
)
|
$
|
2.3
|
$
|
(165.2
|
)
|
|
|
For the Year Ended December 31,
|
|||||||
Losses (gains) on cash flow hedges:
|
Location
|
2020
|
2019
|
||||||
Interest rate derivatives
|
Interest expense
|
$
|
39.3
|
$
|
37.3
|
||||
Commodity derivatives
|
Revenue
|
(282.6
|
)
|
(152.4
|
)
|
||||
Commodity derivatives
|
Operating costs and expenses
|
9.9
|
10.7
|
||||||
Total
|
|
$
|
(233.4
|
)
|
$
|
(104.4
|
)
|
|
At December 31,
|
|||||||
Consolidated Subsidiary
|
2020
|
2019
|
||||||
Breviloba LLC (“Breviloba”)(1)
|
$
|
480.4
|
$
|
492.9
|
||||
Whitethorn Pipeline Company LLC (“Whitethorn”)(2)
|
193.0
|
198.9
|
||||||
Enterprise Navigator Ethylene Terminal LLC (“ENET”)(3)
|
142.2
|
124.3
|
||||||
Other (4)
|
257.7
|
247.4
|
||||||
Total noncontrolling interests in consolidated subsidiaries
|
$
|
1,073.3
|
$
|
1,063.5
|
(1)
|
Altus Midstream Processing LP acquired a noncontrolling 33% equity interest in Breviloba, which owns the Shin Oak NGL Pipeline, in July 2019 for $440.7 million in cash.
|
(2)
|
An affiliate of Western Gas Partners, LP acquired a noncontrolling 20% equity interest in Whitethorn, which owns the majority of our Midland-to-ECHO 1 pipeline, in June 2018 for $189.6 million in cash.
|
(3)
|
Navigator Ethylene Terminals LLC owns a noncontrolling 50% equity interest in ENET, which owns our ethylene export terminal located at Morgan’s Point on the Houston Ship Channel.
|
(4)
|
Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses.
|
|
Quarterly
Distribution Per
Common Unit
|
Record
Date
|
Payment
Date
|
|||
2018:
|
|
|
||||
1st Quarter
|
$
|
0.4275
|
4/30/2018
|
5/8/2018
|
||
2nd Quarter
|
$
|
0.4300
|
7/31/2018
|
8/8/2018
|
||
3rd Quarter
|
$
|
0.4325
|
10/31/2018
|
11/8/2018
|
||
4th Quarter
|
$
|
0.4350
|
1/31/2019
|
2/8/2019
|
||
2019:
|
||||||
1st Quarter
|
$
|
0.4375
|
4/30/2019
|
5/13/2019
|
||
2nd Quarter
|
$
|
0.4400
|
7/31/2019
|
8/13/2019
|
||
3rd Quarter
|
$
|
0.4425
|
10/31/2019
|
11/12/2019
|
||
4th Quarter
|
$
|
0.4450
|
1/31/2020
|
2/12/2020
|
||
2020:
|
|
|
||||
1st Quarter
|
$
|
0.4450
|
4/30/2020
|
5/12/2020
|
||
2nd Quarter
|
$
|
0.4450
|
7/31/2020
|
8/12/2020
|
||
3rd Quarter
|
$
|
0.4450
|
10/30/2020
|
11/12/2020
|
||
4th Quarter
|
$
|
0.4500
|
1/29/2021
|
2/11/2021
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
NGL Pipelines & Services:
|
||||||||||||
Sales of NGLs and related products
|
$
|
8,970.7
|
$
|
10,934.3
|
$
|
12,920.9
|
||||||
Segment midstream services:
|
||||||||||||
Natural gas processing and fractionation
|
757.3
|
1,069.9
|
1,341.0
|
|||||||||
Transportation
|
1,036.8
|
1,054.3
|
1,007.0
|
|||||||||
Storage and terminals
|
412.4
|
412.2
|
380.0
|
|||||||||
Total segment midstream services
|
2,206.5
|
2,536.4
|
2,728.0
|
|||||||||
Total NGL Pipelines & Services
|
11,177.2
|
13,470.7
|
15,648.9
|
|||||||||
Crude Oil Pipelines & Services:
|
||||||||||||
Sales of crude oil
|
5,410.8
|
9,007.8
|
10,001.2
|
|||||||||
Segment midstream services:
|
||||||||||||
Transportation
|
804.9
|
801.8
|
676.5
|
|||||||||
Storage and terminals
|
473.3
|
477.7
|
364.9
|
|||||||||
Total segment midstream services
|
1,278.2
|
1,279.5
|
1,041.4
|
|||||||||
Total Crude Oil Pipelines & Services
|
6,689.0
|
10,287.3
|
11,042.6
|
|||||||||
Natural Gas Pipelines & Services:
|
||||||||||||
Sales of natural gas
|
1,530.5
|
2,075.4
|
2,411.7
|
|||||||||
Segment midstream services:
|
||||||||||||
Transportation
|
1,022.6
|
1,094.0
|
1,042.7
|
|||||||||
Total segment midstream services
|
1,022.6
|
1,094.0
|
1,042.7
|
|||||||||
Total Natural Gas Pipelines & Services
|
2,553.1
|
3,169.4
|
3,454.4
|
|||||||||
Petrochemical & Refined Products Services:
|
||||||||||||
Sales of petrochemicals and refined products
|
5,942.6
|
4,985.2
|
5,535.4
|
|||||||||
Segment midstream services:
|
||||||||||||
Fractionation and isomerization
|
187.7
|
166.6
|
188.3
|
|||||||||
Transportation, including marine logistics
|
482.9
|
539.4
|
481.8
|
|||||||||
Storage and terminals
|
167.2
|
170.6
|
182.8
|
|||||||||
Total segment midstream services
|
837.8
|
876.6
|
852.9
|
|||||||||
Total Petrochemical & Refined Products Services
|
6,780.4
|
5,861.8
|
6,388.3
|
|||||||||
Total consolidated revenues
|
$
|
27,199.7
|
$
|
32,789.2
|
$
|
36,534.2
|
|
December 31,
|
||||||||
Contract Asset
|
Location
|
2020
|
2019
|
||||||
Unbilled revenue (current amount)
|
Prepaid and other current assets
|
$
|
18.8
|
$
|
17.6
|
||||
Total
|
$
|
18.8
|
$
|
17.6
|
|
December 31,
|
||||||||
Contract Liability
|
Location
|
2020
|
2019
|
||||||
Deferred revenue (current amount)
|
Other current liabilities
|
$
|
145.3
|
$
|
117.9
|
||||
Deferred revenue (noncurrent)
|
Other long-term liabilities
|
198.2
|
197.0
|
||||||
Total
|
$
|
343.5
|
$
|
314.9
|
|
Unbilled
Revenue
|
Deferred
Revenue
|
||||||
Balance at January 1, 2018 (upon adoption of ASC 606)
|
$
|
–
|
$
|
224.7
|
||||
Amount included in opening balance transferred to other accounts during period (1)
|
–
|
(90.8
|
)
|
|||||
Amount recorded during period (2)
|
321.7
|
432.5
|
||||||
Amounts recorded during period transferred to other accounts (1)
|
(310.6
|
)
|
(274.8
|
)
|
||||
Amount recorded in connection with business combination
|
2.2
|
–
|
||||||
Other changes
|
–
|
(0.4
|
)
|
|||||
Balance at December 31, 2018
|
$
|
13.3
|
$
|
291.2
|
||||
Amount included in opening balance transferred to other accounts during period (1)
|
(13.3
|
)
|
(126.4
|
)
|
||||
Amount recorded during period (2)
|
340.0
|
539.8
|
||||||
Amounts recorded during period transferred to other accounts (1)
|
(322.4
|
)
|
(384.8
|
)
|
||||
Other changes
|
–
|
(4.9
|
)
|
|||||
Balance at December 31, 2019
|
$
|
17.6
|
$
|
314.9
|
||||
Amount included in opening balance transferred to other accounts during period (1)
|
(17.6
|
)
|
(114.5
|
)
|
||||
Amount recorded during period (2)
|
323.0
|
661.2
|
||||||
Amounts recorded during period transferred to other accounts (1)
|
(304.2
|
)
|
(496.7
|
)
|
||||
Other changes
|
–
|
(21.4
|
)
|
|||||
Balance at December 31, 2020
|
$
|
18.8
|
$
|
343.5
|
(1)
|
Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.
|
(2)
|
Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.
|
Period
|
Fixed Consideration
|
|||
One Year Ended December 31, 2021
|
$
|
3,906.4
|
||
One Year Ended December 31, 2022
|
3,492.3
|
|||
One Year Ended December 31, 2023
|
3,110.2
|
|||
One Year Ended December 31, 2024
|
2,937.3
|
|||
One Year Ended December 31, 2025
|
2,636.5
|
|||
Thereafter
|
12,912.5
|
|||
Total
|
$
|
28,995.2
|
• |
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
|
$
|
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
|
(1)
|
Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper.
|
(2)
|
As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin.
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Gross operating margin by segment:
|
||||||||||||
NGL Pipelines & Services
|
$
|
4,182.4
|
$
|
4,069.8
|
$
|
3,830.7
|
||||||
Crude Oil Pipelines & Services
|
1,997.3
|
2,087.8
|
1,511.3
|
|||||||||
Natural Gas Pipelines & Services
|
926.6
|
1,062.6
|
891.2
|
|||||||||
Petrochemical & Refined Products Services
|
1,081.8
|
1,069.6
|
1,057.8
|
|||||||||
Total segment gross operating margin
|
$
|
8,188.1
|
$
|
8,289.8
|
$
|
7,291.0
|
|
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
|
$
|
11,170.6
|
$
|
6,668.8
|
$
|
2,543.2
|
$
|
6,780.4
|
$
|
–
|
$
|
27,163.0
|
||||||||||||
Year ended December 31, 2019
|
13,460.8
|
10,244.6
|
3,154.7
|
5,861.8
|
–
|
32,721.9
|
||||||||||||||||||
Year ended December 31, 2018
|
15,630.5
|
10,968.2
|
3,439.5
|
6,388.3
|
–
|
36,426.5
|
||||||||||||||||||
Revenues from related parties:
|
||||||||||||||||||||||||
Year ended December 31, 2020
|
6.6
|
20.2
|
9.9
|
–
|
–
|
36.7
|
||||||||||||||||||
Year ended December 31, 2019
|
9.9
|
42.7
|
14.7
|
–
|
–
|
67.3
|
||||||||||||||||||
Year ended December 31, 2018
|
18.4
|
74.4
|
14.9
|
–
|
–
|
107.7
|
||||||||||||||||||
Intersegment and intrasegment revenues:
|
||||||||||||||||||||||||
Year ended December 31, 2020
|
29,010.3
|
24,531.3
|
460.1
|
5,379.4
|
(59,381.1
|
)
|
–
|
|||||||||||||||||
Year ended December 31, 2019
|
20,840.4
|
34,613.0
|
624.7
|
2,481.3
|
(58,559.4
|
)
|
–
|
|||||||||||||||||
Year ended December 31, 2018
|
26,453.6
|
35,490.4
|
721.9
|
2,917.5
|
(65,583.4
|
)
|
–
|
|||||||||||||||||
Total revenues:
|
||||||||||||||||||||||||
Year ended December 31, 2020
|
40,187.5
|
31,220.3
|
3,013.2
|
12,159.8
|
(59,381.1
|
)
|
27,199.7
|
|||||||||||||||||
Year ended December 31, 2019
|
34,311.1
|
44,900.3
|
3,794.1
|
8,343.1
|
(58,559.4
|
)
|
32,789.2
|
|||||||||||||||||
Year ended December 31, 2018
|
42,102.5
|
46,533.0
|
4,176.3
|
9,305.8
|
(65,583.4
|
)
|
36,534.2
|
|||||||||||||||||
Equity in income (loss) of unconsolidated affiliates:
|
||||||||||||||||||||||||
Year ended December 31, 2020
|
121.3
|
301.2
|
5.8
|
(2.2
|
)
|
–
|
426.1
|
|||||||||||||||||
Year ended December 31, 2019
|
114.5
|
449.2
|
6.3
|
(7.0
|
)
|
–
|
563.0
|
|||||||||||||||||
Year ended December 31, 2018
|
117.0
|
365.4
|
6.8
|
(9.2
|
)
|
–
|
480.0
|
|
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
|
$
|
17,128.3
|
$
|
6,982.6
|
$
|
8,465.8
|
$
|
7,528.4
|
$
|
1,807.7
|
$
|
41,912.8
|
||||||||||||
At December 31, 2019
|
16,652.1
|
6,324.4
|
8,432.5
|
7,553.2
|
2,641.2
|
41,603.4
|
||||||||||||||||||
At December 31, 2018
|
14,845.4
|
5,847.7
|
8,303.8
|
6,213.9
|
3,526.8
|
38,737.6
|
||||||||||||||||||
Investments in unconsolidated affiliates: (see Note 5)
|
||||||||||||||||||||||||
At December 31, 2020
|
671.6
|
1,723.7
|
31.4
|
2.5
|
–
|
2,429.2
|
||||||||||||||||||
At December 31, 2019
|
703.8
|
1,866.5
|
27.3
|
2.6
|
–
|
2,600.2
|
||||||||||||||||||
At December 31, 2018
|
662.0
|
1,867.5
|
22.8
|
62.8
|
–
|
2,615.1
|
||||||||||||||||||
Intangible assets, net: (see Note 6)
|
||||||||||||||||||||||||
At December 31, 2020
|
334.1
|
1,936.6
|
905.0
|
133.4
|
–
|
3,309.1
|
||||||||||||||||||
At December 31, 2019
|
360.2
|
2,001.9
|
941.2
|
145.7
|
–
|
3,449.0
|
||||||||||||||||||
At December 31, 2018
|
380.1
|
2,094.6
|
979.3
|
154.4
|
–
|
3,608.4
|
||||||||||||||||||
Goodwill: (see Note 6)
|
||||||||||||||||||||||||
At December 31, 2020
|
2,651.7
|
1,841.0
|
–
|
956.2
|
–
|
5,448.9
|
||||||||||||||||||
At December 31, 2019
|
2,651.7
|
1,841.0
|
296.3
|
956.2
|
–
|
5,745.2
|
||||||||||||||||||
At December 31, 2018
|
2,651.7
|
1,841.0
|
296.3
|
956.2
|
–
|
5,745.2
|
||||||||||||||||||
Segment assets:
|
||||||||||||||||||||||||
At December 31, 2020
|
20,785.7
|
12,483.9
|
9,402.2
|
8,620.5
|
1,807.7
|
53,100.0
|
||||||||||||||||||
At December 31, 2019
|
20,367.8
|
12,033.8
|
9,697.3
|
8,657.7
|
2,641.2
|
53,397.8
|
||||||||||||||||||
At December 31, 2018
|
18,539.2
|
11,650.8
|
9,602.2
|
7,387.3
|
3,526.8
|
50,706.3
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Consolidated revenues:
|
||||||||||||
NGL Pipelines & Services
|
$
|
11,177.2
|
$
|
13,470.7
|
$
|
15,648.9
|
||||||
Crude Oil Pipelines & Services
|
6,689.0
|
10,287.3
|
11,042.6
|
|||||||||
Natural Gas Pipelines & Services
|
2,553.1
|
3,169.4
|
3,454.4
|
|||||||||
Petrochemical & Refined Products Services
|
6,780.4
|
5,861.8
|
6,388.3
|
|||||||||
Total consolidated revenues
|
$
|
27,199.7
|
$
|
32,789.2
|
$
|
36,534.2
|
||||||
|
||||||||||||
Consolidated costs and expenses:
|
||||||||||||
Operating costs and expenses:
|
||||||||||||
Cost of sales
|
$
|
16,723.2
|
$
|
22,065.8
|
$
|
26,789.8
|
||||||
Other operating costs and expenses (1)
|
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
|
–
|
–
|
|||||||||
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 consolidated costs and expenses
|
$
|
22,590.7
|
$
|
27,273.5
|
$
|
31,605.6
|
(1)
|
Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment and related charges; and net losses (or gains) attributable to asset sales.
|
NGL Pipelines & Services
|
$
|
1,410.8
|
||
Crude Oil Pipelines & Services
|
1,670.7
|
|||
Natural Gas Pipelines & Services
|
31.2
|
|||
Petrochemical & Refined Products Services
|
202.1
|
|||
Total
|
$
|
3,314.8
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
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
|
2,185.8
|
2,188.6
|
2,176.5
|
|||||||||
|
||||||||||||
Basic earnings per common 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
|
–
|
–
|
|||||||||
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
|
2,185.8
|
2,188.6
|
2,176.5
|
|||||||||
Phantom units (2)
|
15.7
|
13.1
|
10.5
|
|||||||||
Preferred units (2)
|
0.7
|
–
|
–
|
|||||||||
Total
|
2,202.2
|
2,201.7
|
2,187.0
|
|||||||||
|
||||||||||||
Diluted earnings per common unit
|
$
|
1.71
|
$
|
2.09
|
$
|
1.91
|
(1)
|
Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding our phantom units.
|
(2)
|
We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom units and the conversion of preferred units outstanding. See Note 8 for information regarding the preferred units issued during 2020.
|
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
|
$
|
300.9
|
||
Recognized amounts of identifiable assets acquired and liabilities assumed:
|
||||
Assets acquired in business combination:
|
||||
Current assets, including cash of $3.9 million
|
$
|
10.8
|
||
Property, plant and equipment
|
200.0
|
|||
Contract-based intangible assets
|
82.6
|
|||
Customer relationship intangible assets
|
9.9
|
|||
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
|
$
|
–
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Equity-classified awards:
|
||||||||||||
Phantom unit awards
|
$
|
150.3
|
$
|
132.2
|
$
|
99.7
|
||||||
Profits interest awards
|
8.7
|
11.6
|
6.1
|
|||||||||
Liability-classified awards
|
0.1
|
0.1
|
0.3
|
|||||||||
Total
|
$
|
159.1
|
$
|
143.9
|
$
|
106.1
|
|
Number of
Units
|
Weighted-
Average Grant
Date Fair Value
per Unit (1)
|
||||||
Phantom unit awards at December 31, 2017
|
9,289,501
|
$
|
27.65
|
|||||
Granted (2)
|
5,006,181
|
$
|
26.82
|
|||||
Vested
|
(3,479,958
|
)
|
$
|
28.57
|
||||
Forfeited
|
(482,447
|
)
|
$
|
26.88
|
||||
Phantom unit awards at December 31, 2018
|
10,333,277
|
$
|
26.97
|
|||||
Granted (3)
|
6,854,920
|
$
|
27.75
|
|||||
Vested
|
(3,895,049
|
)
|
$
|
27.53
|
||||
Forfeited
|
(318,464
|
)
|
$
|
27.21
|
||||
Phantom unit awards at December 31, 2019
|
12,974,684
|
$
|
27.21
|
|||||
Granted (4)
|
7,405,245
|
$
|
25.71
|
|||||
Vested
|
(4,532,269
|
)
|
$
|
26.35
|
||||
Forfeited
|
(178,218
|
)
|
$
|
26.73
|
||||
Phantom unit awards at December 31, 2020
|
15,669,442
|
$
|
26.76
|
(1)
|
Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.
|
(2)
|
The aggregate grant date fair value of phantom unit awards issued during 2018 was $134.3 million based on a grant date market price of EPD common units ranging from $25.40 to $29.22 per unit. An estimated annual forfeiture rate of 3.2% was applied to these awards.
|
(3)
|
The aggregate grant date fair value of phantom unit awards issued during 2019 was $190.2 million based on a grant date market price of EPD common units ranging from $26.32 to $29.29 per unit. An estimated annual forfeiture rate of 3.0% was applied to these awards.
|
(4)
|
The aggregate grant date fair value of phantom unit awards issued during 2020 was $190.4 million based on a grant date market price of EPD common units ranging from $16.95 to $25.76 per unit. An estimated annual forfeiture rate of 2.4% was applied to these awards.
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
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
|
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
|
2,834,198
|
$66.3 million
|
$0.3900
|
February 2023
|
$2.5 million
|
$2.3 million
|
PrivCo I
|
1,111,438
|
$26.0 million
|
$0.3900
|
February 2023
|
$0.9 million
|
$0.2 million
|
EPD IV
|
6,400,000
|
$172.9 million
|
$0.4325
|
December 2023
|
$26.7 million
|
$13.6 million
|
EPCO II
|
1,600,000
|
$43.2 million
|
$0.4325
|
December 2023
|
$6.6 million
|
$0.3 million
|
(1)
|
Represents the fair market value of EPD common units contributed to each Employee Partnership at the applicable contribution date.
|
(2)
|
Represents the total fair value of the profits interest awards awarded to the Class B limited partners of each Employee Partnership irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates. The fair value is as of the grant date or as of the plan modification date, as applicable.
|
(3)
|
Represents our expected share of the unrecognized compensation cost at December 31, 2020. We expect to recognize our share of the unrecognized compensation cost for PubCo II, PrivCo I, EPD IV and EPCO II over a weighted-average period of 2.1 years, 2.1 years, 2.9 years and 2.9 years, respectively.
|
|
Expected Life
|
Risk-Free
|
Expected
|
Expected Unit
|
Employee
|
of Award
|
Interest
|
Distribution
|
Price
|
Partnership
|
from Grant Date
|
Rate
|
Yield
|
Volatility
|
PubCo II
|
7.0 years
|
0.1% to 3.0%
|
5.9% to 7.0%
|
19% to 40%
|
PrivCo I
|
7.0 years
|
0.1% to 1.6%
|
6.1% to 6.7%
|
19% to 40%
|
EPD IV
|
5.0 years
|
2.8%
|
6.5%
|
27%
|
EPCO II
|
5.0 years
|
1.6% to 2.8%
|
6.3% to 6.8%
|
24% to 27%
|
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.
|
• |
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)
|
6.0
|
n/a
|
Cash flow hedge
|
||
Forecasted sales of NGLs (MMBbls)
|
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 transportation, processing and storage assets.
|
|
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
|
$
|
109.1
|
Current
liabilities
|
$
|
6.7
|
|||
Interest rate derivatives
|
Other assets
|
12.4
|
Other assets
|
–
|
Other liabilities
|
11.0
|
Other liabilities
|
6.8
|
|||||||
Total interest rate derivatives
|
12.4
|
–
|
120.1
|
13.5
|
|||||||||||
Commodity derivatives
|
Current assets
|
210.5
|
|
Current assets
|
116.5
|
|
Current
liabilities
|
234.0
|
|
Current
liabilities
|
107.1
|
||||
Commodity derivatives
|
Other assets
|
|
0.4
|
|
Other assets
|
|
–
|
|
Other liabilities
|
|
6.1
|
|
Other liabilities
|
|
–
|
Total commodity derivatives
|
210.9
|
116.5
|
240.1
|
107.1
|
|||||||||||
Total derivatives designated as hedging instruments
|
$
|
223.3
|
$
|
116.5
|
$
|
360.2
|
$
|
120.6
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|||||||||||||||
Commodity derivatives
|
Current assets
|
|
18.1
|
|
Current assets
|
10.7
|
|
Current
liabilities
|
6.1
|
|
Current
liabilities
|
8.6
|
|||
Commodity derivatives
|
Other assets
|
|
0.2
|
|
Other assets
|
0.6
|
|
Other liabilities
|
0.1
|
|
Other liabilities
|
0.5
|
|||
Total commodity derivatives
|
|
|
18.3
|
|
|
11.3
|
|
|
6.2
|
|
|
9.1
|
|||
Total derivatives not designated as hedging instruments
|
$
|
18.3
|
$
|
11.3
|
$
|
6.2
|
$
|
9.1
|
|
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
|
$
|
12.4
|
$
|
–
|
$
|
12.4
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
12.4
|
||||||||||||||
Commodity derivatives
|
229.2
|
–
|
229.2
|
(228.5
|
)
|
–
|
–
|
0.7
|
||||||||||||||||||||
As of December 31, 2019:
|
||||||||||||||||||||||||||||
Commodity derivatives
|
$
|
127.8
|
–
|
$
|
127.8
|
$
|
(115.3
|
)
|
$
|
(11.0
|
)
|
$
|
–
|
$
|
1.5
|
|
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
|
$
|
120.1
|
$
|
–
|
$
|
120.1
|
$
|
–
|
$
|
–
|
$
|
120.1
|
||||||||||||
Commodity derivatives
|
246.3
|
–
|
246.3
|
(228.5
|
)
|
(17.3
|
)
|
0.5
|
||||||||||||||||
As of December 31, 2019:
|
||||||||||||||||||||||||
Interest rate derivatives
|
$
|
13.5
|
$
|
–
|
$
|
13.5
|
$
|
–
|
$
|
–
|
$
|
13.5
|
||||||||||||
Commodity derivatives
|
116.2
|
–
|
116.2
|
(115.3
|
)
|
–
|
0.9
|
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
|
$
|
–
|
$
|
–
|
$
|
1.3
|
||||||
Commodity derivatives
|
Revenue
|
(88.0
|
)
|
2.2
|
9.9
|
||||||||
Total
|
|
$
|
(88.0
|
)
|
$
|
2.2
|
$
|
11.2
|
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
|
$
|
–
|
$
|
–
|
$
|
(1.4
|
)
|
|||||
Commodity derivatives
|
Revenue
|
168.1
|
6.9
|
(6.9
|
)
|
||||||||
Total
|
|
$
|
168.1
|
$
|
6.9
|
$
|
(8.3
|
)
|
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
|
$
|
(127.5
|
)
|
$
|
81.4
|
$
|
22.2
|
|||||
Commodity derivatives – Revenue (1)
|
134.7
|
55.8
|
293.0
|
|||||||||
Commodity derivatives – Operating costs and expenses (1)
|
(10.3
|
)
|
(11.7
|
)
|
0.2
|
|||||||
Total
|
$
|
(3.1
|
)
|
$
|
125.5
|
$
|
315.4
|
(1)
|
The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings.
|
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
|
$
|
(39.3
|
)
|
$
|
(37.3
|
)
|
$
|
(38.1
|
)
|
|||
Commodity derivatives
|
Revenue
|
282.6
|
152.4
|
131.7
|
|||||||||
Commodity derivatives
|
Operating costs and expenses
|
(9.9
|
)
|
(10.7
|
)
|
(1.3
|
)
|
||||||
Total
|
|
$
|
233.4
|
$
|
104.4
|
$
|
92.3
|
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
|
$
|
–
|
$
|
(94.9
|
)
|
$
|
–
|
|||||
Commodity derivatives
|
Revenue
|
166.0
|
102.2
|
(462.9
|
)
|
||||||||
Commodity derivatives
|
Operating costs and expenses
|
(0.2
|
)
|
(12.4
|
)
|
8.2
|
|||||||
Total
|
|
$
|
165.8
|
$
|
(5.1
|
)
|
$
|
(454.7
|
)
|
For the Year Ended December 31,
|
||||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Mark-to-market gains (losses) in gross operating margin:
|
||||||||||||
NGL Pipelines & Services
|
$
|
48.4
|
$
|
(5.5
|
)
|
$
|
18.0
|
|||||
Crude Oil Pipelines & Services
|
20.1
|
80.6
|
(44.1
|
)
|
||||||||
Natural Gas Pipelines & Services
|
6.3
|
(0.2
|
)
|
6.7
|
||||||||
Petrochemical & Refined Products Services
|
4.5
|
(7.2
|
)
|
1.7
|
||||||||
Total mark-to-market impact on gross operating margin
|
79.3
|
67.7
|
(17.7
|
)
|
||||||||
Mark-to-market gains (losses) in interest expense
|
–
|
(94.9
|
)
|
(0.1
|
)
|
|||||||
Total
|
$
|
79.3
|
$
|
(27.2
|
)
|
$
|
(17.8
|
)
|
|
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
|
$
|
–
|
$
|
12.4
|
$
|
–
|
$
|
12.4
|
||||||||
Commodity derivatives:
|
||||||||||||||||
Value before application of CME Rule 814
|
678.6
|
878.6
|
12.9
|
1,570.1
|
||||||||||||
Impact of CME Rule 814 change
|
(678.6
|
)
|
(650.4
|
)
|
(11.9
|
)
|
(1,340.9
|
)
|
||||||||
Total commodity derivatives
|
–
|
228.2
|
1.0
|
229.2
|
||||||||||||
Total
|
$
|
–
|
$
|
240.6
|
$
|
1.0
|
$
|
241.6
|
||||||||
|
||||||||||||||||
Financial liabilities:
|
||||||||||||||||
Interest rate derivatives
|
$
|
–
|
$
|
120.1
|
$
|
–
|
$
|
120.1
|
||||||||
Commodity derivatives:
|
||||||||||||||||
Value before application of CME Rule 814
|
1,065.6
|
1,047.4
|
25.9
|
2,138.9
|
||||||||||||
Impact of CME Rule 814 change
|
(1,065.6
|
)
|
(807.3
|
)
|
(19.7
|
)
|
(1,892.6
|
)
|
||||||||
Total commodity derivatives
|
–
|
240.1
|
6.2
|
246.3
|
||||||||||||
Total
|
$
|
–
|
$
|
360.2
|
$
|
6.2
|
$
|
366.4
|
|
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
|
$
|
53.4
|
$
|
343.7
|
$
|
0.1
|
$
|
397.2
|
||||||||
Impact of CME Rule 814 change
|
(47.0
|
)
|
(222.4
|
)
|
–
|
(269.4
|
)
|
|||||||||
Total commodity derivatives
|
6.4
|
121.3
|
0.1
|
127.8
|
||||||||||||
Total
|
$
|
6.4
|
$
|
121.3
|
$
|
0.1
|
$
|
127.8
|
||||||||
|
||||||||||||||||
Financial liabilities:
|
||||||||||||||||
Liquidity Option (see Note 17)
|
$
|
–
|
$
|
–
|
$
|
509.6
|
$
|
509.6
|
||||||||
Interest rate derivatives
|
–
|
13.5
|
–
|
13.5
|
||||||||||||
Commodity derivatives:
|
||||||||||||||||
Value before application of CME Rule 814
|
88.1
|
273.6
|
0.3
|
362.0
|
||||||||||||
Impact of CME Rule 814 change
|
(81.9
|
)
|
(163.9
|
)
|
–
|
(245.8
|
)
|
|||||||||
Total commodity derivatives
|
6.2
|
109.7
|
0.3
|
116.2
|
||||||||||||
Total
|
$
|
6.2
|
$
|
123.2
|
$
|
509.9
|
$
|
639.3
|
test
|
|
For the Year Ended December 31,
|
|||||||
test
|
Location
|
2020
|
2019
|
||||||
Financial liability balance, net, January 1
|
|
$
|
(509.8
|
)
|
$
|
(395.9
|
)
|
||
Total gains (losses) included in:
|
|
||||||||
Net income (1)
|
Revenue
|
(1.6
|
)
|
3.7
|
|||||
Net income
|
Other expense, net – Liquidity Option
|
(2.3
|
)
|
(119.6
|
)
|
||||
Other comprehensive income (loss)
|
Commodity derivative instruments – changes in fair value of cash flow hedges
|
(23.7
|
)
|
(2.1
|
)
|
||||
Settlements (1)
|
Revenue
|
3.2
|
(3.5
|
)
|
|||||
Transfer out of Level 3 – Liquidity Option (2)
|
511.9
|
–
|
|||||||
Other transfers out of Level 3
|
|
17.1
|
7.6
|
||||||
Financial liability balance, net, December 31
|
|
$
|
(5.2
|
)
|
$
|
(509.8
|
)
|
(1)
|
There were $0.7 million and $0.2 million of unrealized gains included in these amounts for the years ended December 31, 2020 and 2019, respectively.
|
(2)
|
In March 2020, the Liquidity Option settled and was transferred out of Level 3. See Note 17 for information regarding the Liquidity Option.
|
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
|
$
|
–
|
$
|
–
|
$
|
410.0
|
$
|
410.0
|
$
|
256.7
|
||||||||||
South Texas natural gas gathering and processing
|
–
|
–
|
21.3
|
21.3
|
125.7
|
(1)
|
Our fair value estimates for these assets were based on an income approach (i.e., a discounted cash flow approach).
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Revenues – related parties:
|
||||||||||||
Unconsolidated affiliates
|
$
|
36.7
|
$
|
67.3
|
$
|
107.7
|
||||||
Costs and expenses – related parties:
|
||||||||||||
EPCO and its privately held affiliates
|
$
|
1,143.7
|
$
|
1,145.3
|
$
|
1,089.6
|
||||||
Unconsolidated affiliates
|
203.1
|
403.1
|
447.4
|
|||||||||
Total
|
$
|
1,346.8
|
$
|
1,548.4
|
$
|
1,537.0
|
|
December 31,
|
|||||||
|
2020
|
2019
|
||||||
Accounts receivable - related parties:
|
||||||||
EPCO and its privately held affiliates
|
$
|
1.9
|
$
|
–
|
||||
Unconsolidated affiliates
|
3.7
|
2.5
|
||||||
Total
|
$
|
5.6
|
$
|
2.5
|
||||
|
||||||||
Accounts payable - related parties:
|
||||||||
EPCO and its privately held affiliates
|
$
|
139.6
|
$
|
143.7
|
||||
Unconsolidated affiliates
|
9.9
|
18.6
|
||||||
Total
|
$
|
149.5
|
$
|
162.3
|
Total Number of Limited Partner Interests Held
|
Percentage of
Limited Partner
Interests
Outstanding
|
|||
701,993,298 common units
|
32.2
|
%
|
||
15,138 preferred units
|
30.2
|
%
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
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
|
$
|
1,127.9
|
$
|
1,127.8
|
$
|
1,073.0
|
• |
For the years ended December 31, 2020, 2019 and 2018, we paid Seaway $71.5 million, $194.5 million and $163.2 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $20.2 million, $42.7 million and $74.4 million for the years ended December 31, 2020, 2019 and 2018, respectively.
|
• |
For the years ended December 31, 2020, 2019 and 2018, we purchased $51.3 million, $89.2 million and $157.9 million, respectively, of NGLs from VESCO.
|
• |
We pay Promix for the transportation, storage and fractionation of NGLs. Expenses with Promix were $23.5 million, $34.8 million and $31.9 million for the years ended December 31, 2020, 2019 and 2018, respectively. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $6.0 million, $9.1 million and $9.5 million for the years ended December 31, 2020, 2019 and 2018, respectively.
|
• |
For the years ended December 31, 2020, 2019 and 2018, we paid Texas Express $29.1 million, $33.5 million and $57.6 million, respectively, for pipeline transportation services.
|
• |
For the years ended December 31, 2020, 2019 and 2018, we paid Eagle Ford Crude Oil Pipeline $20.9 million, $36.0 million and $18.5 million, respectively, for pipeline transportation services.
|
• |
We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $10.1 million, $9.9 million and $11.6 million for the years ended December 31, 2020, 2019 and 2018, respectively.
|
For the Year Ended December 31,
|
||||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Deferred tax benefit attributable to OTA
|
$
|
155.3
|
$
|
–
|
$
|
–
|
||||||
Texas Margin Tax
|
(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
|
)
|
For the Year Ended December 31,
|
||||||||||||
|
2020
|
2019
|
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
|
–
|
0.1
|
–
|
|||||||||
Total deferred portion
|
147.6
|
(20.0
|
)
|
(21.4
|
)
|
|||||||
Total benefit from (provision for) income taxes
|
$
|
124.3
|
$
|
(45.6
|
)
|
$
|
(60.3
|
)
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
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
|
–
|
–
|
|||||||||
Other differences
|
(0.7
|
)
|
–
|
(3.2
|
)
|
|||||||
Benefit from (provision for) income taxes
|
$
|
124.3
|
$
|
(45.6
|
)
|
$
|
(60.3
|
)
|
||||
|
||||||||||||
Effective income tax rate
|
3.3
|
%
|
(1.0
|
)%
|
(1.4
|
)%
|
(1)
|
Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
|
(2)
|
The total benefit recognized in income tax expense on March 5, 2020 from settlement of the Liquidity Option was $72.2 million, which is comprised of $4.4 million of state income tax benefit and $67.8 million of federal income tax benefit.
|
|
December 31,
|
|||||||
|
2020
|
2019
|
||||||
Deferred tax liabilities:
|
||||||||
Attributable to investment in OTA
|
$
|
356.6
|
$
|
–
|
||||
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
|
(1)
|
These losses expire in various years between 2021 and 2037 and are subject to limitations on their utilization.
|
|
Payment or Settlement due by Period
|
|||||||||||||||||||||||||||
Contractual Obligations
|
Total
|
2021
|
2022
|
2023
|
2024
|
2025
|
Thereafter
|
|||||||||||||||||||||
Scheduled maturities of debt obligations
|
$
|
30,146.4
|
$
|
1,325.0
|
$
|
1,400.0
|
$
|
1,250.0
|
$
|
850.0
|
$
|
1,150.0
|
$
|
24,171.4
|
||||||||||||||
Estimated cash interest payments
|
$
|
28,834.6
|
$
|
1,294.0
|
$
|
1,241.2
|
$
|
1,201.0
|
$
|
1,162.8
|
$
|
1,121.4
|
$
|
22,814.2
|
||||||||||||||
Operating lease obligations
|
$
|
460.5
|
$
|
33.7
|
$
|
36.1
|
$
|
33.2
|
$
|
29.9
|
$
|
28.8
|
$
|
298.8
|
||||||||||||||
Purchase obligations:
|
||||||||||||||||||||||||||||
Product purchase commitments:
|
||||||||||||||||||||||||||||
Estimated payment obligations:
|
||||||||||||||||||||||||||||
Natural gas
|
$
|
155.0
|
$
|
84.6
|
$
|
70.4
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||||||||
NGLs
|
$
|
3,908.4
|
$
|
685.2
|
$
|
696.8
|
$
|
494.4
|
$
|
436.4
|
$
|
336.8
|
$
|
1,258.8
|
||||||||||||||
Crude oil
|
$
|
10,365.7
|
$
|
1,390.1
|
$
|
1,390.1
|
$
|
1,390.1
|
$
|
1,354.9
|
$
|
1,297.2
|
$
|
3,543.3
|
||||||||||||||
Petrochemicals and refined products
|
$
|
346.1
|
$
|
100.9
|
$
|
100.9
|
$
|
76.0
|
$
|
68.3
|
$
|
–
|
$
|
–
|
||||||||||||||
Other
|
$
|
25.5
|
$
|
5.8
|
$
|
5.9
|
$
|
6.0
|
$
|
5.1
|
$
|
2.7
|
$
|
–
|
||||||||||||||
Service payment commitments
|
$
|
278.8
|
$
|
62.0
|
$
|
59.7
|
$
|
42.3
|
$
|
16.1
|
$
|
12.9
|
$
|
85.8
|
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
|
$
|
128.0
|
$
|
128.7
|
15 years
|
4.3
|
%
|
||||||
Transportation equipment
|
33.5
|
35.6
|
3 years
|
3.5
|
%
|
||||||||
Office and warehouse space
|
170.5
|
184.3
|
16 years
|
3.2
|
%
|
||||||||
Total
|
$
|
332.0
|
$
|
348.6
|
(1)
|
ROU asset amounts are a component of “Other assets” on our Consolidated Balance Sheet.
|
(2)
|
At December 31, 2020, lease liabilities of $27.8 million and $320.8 million were included within “Other current liabilities” and “Other liabilities,” respectively.
|
(3)
|
The discount rate for each category of assets represents the weighted average incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842.
|
For the Year
Ended December,
|
||||||||
|
2020
|
2019
|
||||||
Long-term operating leases:
|
||||||||
Fixed lease expense:
|
||||||||
Non-cash lease expense (amortization of ROU assets)
|
$
|
39.0
|
$
|
42.8
|
||||
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
|
• |
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)
|
$
|
137.6
|
$
|
126.9
|
||||
Deferred revenues – non-current portion (see Note 9)
|
198.2
|
197.0
|
||||||
Liquidity Option liability
|
–
|
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
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
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
|
||||||
|
||||||||||||
Cash payments for federal and state income taxes
|
$
|
25.1
|
$
|
23.6
|
$
|
15.5
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Sale of crude oil pipeline system
|
$
|
–
|
$
|
–
|
$
|
134.9
|
||||||
Other asset sales
|
12.8
|
20.6
|
26.3
|
|||||||||
Total
|
$
|
12.8
|
$
|
20.6
|
$
|
161.2
|
|
For the Year Ended December 31,
|
|||||||||||
|
2020
|
2019
|
2018
|
|||||||||
Gain on sale of crude oil pipeline system
|
$
|
–
|
$
|
–
|
$
|
20.6
|
||||||
Net gains attributable to other asset sales
|
4.4
|
5.7
|
8.1
|
|||||||||
Total
|
$
|
4.4
|
$
|
5.7
|
$
|
28.7
|
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 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.
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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;
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3.
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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;
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4.
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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:
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a)
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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;
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b)
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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;
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c)
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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
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d)
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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
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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
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b)
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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.
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/s/ A. James Teague
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||
Name:
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A. James Teague
|
|
Title:
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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.
|