DELAWARE
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76-0568219
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(State or Other Jurisdiction of
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(I.R.S. Employer Identification No.)
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Incorporation or Organization)
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1100 LOUISIANA STREET, 10th FLOOR, HOUSTON, TEXAS 77002
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(Address of Principal Executive Offices) (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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Name of Each Exchange On Which Registered
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Common Units
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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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= 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
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= million British thermal units
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BPD
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= barrels per day
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MMcf
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= million cubic feet
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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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§
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capitalize on expected increases in the production of natural gas, NGLs and crude oil from development activities in various producing basins including the Rocky Mountains, Midcontinent, Northeast and U.S. Gulf Coast regions, deepwater Gulf of Mexico and developing shale plays, including the Barnett, Eagle Ford, Haynesville, Marcellus, Mancos and Utica Shales;
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capitalize on expected demand growth 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 joint ventures or alliances with strategic partners, including those that will provide the raw materials for these growth capital projects or purchase the projects' end products.
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Net Gas
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Total Gas
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Our
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Processing
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Processing
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Ownership
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Capacity
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Capacity
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Description of Asset
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Location(s)
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Interest
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(Bcf/d) (1)
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(Bcf/d)
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Natural gas processing facilities:
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Meeker
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Colorado
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100.0%
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1.70
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1.70
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Pioneer (two facilities)
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Wyoming
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100.0%
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1.35
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1.35
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Yoakum
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Texas
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100.0%
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0.70
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0.70
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Toca
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Louisiana
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68.0% (2)
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0.66
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1.10
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Chaco
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New Mexico
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100.0%
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0.60
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0.60
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North Terrebonne
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Louisiana
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60.0% (2)
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0.57
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0.95
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Neptune
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Louisiana
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66.0% (2)
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0.43
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0.65
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Pascagoula
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Mississippi
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40.0% (2)
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0.40
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1.50
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Thompsonville
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Texas
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100.0%
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0.33
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0.33
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Shoup
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Texas
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100.0%
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0.29
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0.29
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Sea Robin
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Louisiana
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40.0% (2)
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0.28
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0.65
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Gilmore
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Texas
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100.0%
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0.25
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0.25
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Armstrong
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Texas
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100.0%
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0.25
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0.25
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San Martin
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Texas
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100.0%
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0.20
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0.20
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Delmita
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Texas
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100.0%
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0.15
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0.15
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Carlsbad
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New Mexico
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100.0%
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0.13
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0.13
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Sonora
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Texas
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100.0%
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0.12
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0.12
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Shilling
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Texas
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100.0%
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0.11
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0.11
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Venice
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Louisiana
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13.1% (3)
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0.10
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0.75
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Indian Springs
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Texas
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75.0% (2)
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0.09
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0.12
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Burns Point
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Louisiana
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50.0% (2)
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0.08
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0.16
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Indian Basin
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New Mexico
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42.4% (2)
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0.08
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0.18
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Chaparral
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New Mexico
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100.0%
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0.04
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0.04
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Total processing capacities
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8.91
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12.28
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(1) The approximate net gas processing capacity does not necessarily correspond to our ownership interest in each facility. It is based on a variety of factors such as the level of volumes an owner processes at the facility and its ownership interest in the facility.
(2) We proportionately consolidate our undivided interest in these operating assets.
(3) Our ownership in the Venice plant is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C. ("VESCO").
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Our
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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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NGL pipelines:
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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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7,840
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South Texas NGL Pipeline System
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Texas
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100.0%
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1,598
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Seminole Pipeline (1)
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Texas
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100.0%
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1,373
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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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1,306
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Chaparral NGL System (1)
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Texas, New Mexico
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100.0%
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1,011
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Louisiana Pipeline System
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Louisiana
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100.0%
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955
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Skelly-Belvieu Pipeline (3)
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Texas
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50.0% (2)
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572
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Promix NGL Gathering System
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Louisiana
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50.0% (4)
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360
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Houston Ship Channel
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Texas
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100.0%
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300
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Rio Grande Pipeline (3)
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Texas
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70.0% (5)
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249
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Panola Pipeline
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Texas
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100.0%
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223
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Lou-Tex NGL Pipeline (3)
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Texas, Louisiana
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100.0%
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204
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South Dean Pipeline
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Texas
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100.0%
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186
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Tri-States NGL Pipeline (3)
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Alabama, Mississippi, Louisiana
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83.3% (6)
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167
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Chunchula Pipeline (3)
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Alabama, Mississippi
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100.0%
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144
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Others (five systems) (7)
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Various
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Various (8)
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242
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Total miles
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16,730
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(1) Interstate and intrastate transportation services provided by these liquids pipelines are regulated by governmental agencies.
(2) Our ownership interest in the Skelly-Belvieu Pipeline is held indirectly through our equity method investment in Skelly-Belvieu Pipeline Company, L.L.C. ("Skelly-Belvieu").
(3) Interstate transportation services provided by these liquids pipelines are regulated by governmental agencies.
(4) Our ownership interest in the Promix NGL Gathering System is held indirectly through our equity method investment in K/D/S Promix, L.L.C. ("Promix").
(5) We own a 70% consolidated interest in the Rio Grande Pipeline through our majority owned subsidiary, Rio Grande Pipeline Company.
(6) 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.
(7) Includes our Belle Rose and Wilprise pipelines located in the coastal regions of Louisiana and Mississippi; our two Port Arthur pipelines located in southeast Texas; and our Meeker pipeline in Colorado.
(8) We own a 74.7% consolidated interest in the 30-mile Wilprise pipeline through our majority owned subsidiary, Wilprise Pipeline Company, LLC. We proportionately consolidate our 50% undivided interest in a 45-mile segment of the Port Arthur pipelines. The remainder of these NGL pipelines are wholly owned.
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The Mid-America Pipeline System is an NGL pipeline system consisting of four primary segments: the 2,920-mile Rocky Mountain pipeline, the 2,146-mile Conway North pipeline, the 621-mile Ethane-Propane Mix pipeline and the 2,153-mile Conway South pipeline. The Mid-America Pipeline System is present in 13 states: Colorado, Illinois, Iowa, Kansas, Minnesota, Missouri, Nebraska, New Mexico, Oklahoma, Texas, Utah, Wisconsin and Wyoming. The Rocky Mountain pipeline transports mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the Hobbs hub located on the Texas-New Mexico border. The Conway North segment links the NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest. NGL hubs such as those at Hobbs and Conway provide buyers and sellers a centralized location for the storage and pricing of products, while also providing connections to intrastate and/or interstate pipelines. In addition, the Conway North segment has access to NGL supplies from Canada's Western Sedimentary Basin through third party connections. The Ethane-Propane Mix segment transports ethane/propane mix primarily to petrochemical plants in Iowa and Illinois from the NGL hub at Conway. The Conway South pipeline connects the Conway hub with Kansas refineries and provides bi-directional transportation of NGLs between Conway, Kansas and the Hobbs hub. The Mid-America Pipeline System interconnects with our Seminole Pipeline and Hobbs NGL fractionation and storage facility at the Hobbs hub. This system connects to 19 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. The system gathers and transports mixed NGLs from natural gas processing plants in South Texas owned by us and our third party customers to our South Texas NGL fractionators, including those at our Mont Belvieu complex. In turn, the system transports purity NGL products from our South Texas NGL fractionators to refineries and petrochemical plants located between Corpus Christi, Texas and Houston, Texas and within the Texas City-Houston area, as well as to interconnects with common carrier NGL pipelines. The South Texas NGL Pipeline System also connects our South Texas NGL fractionators with our storage facility in Mont Belvieu, Texas.
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The Seminole Pipeline transports NGLs from the Hobbs hub and the Permian Basin area of West Texas to markets in southeast Texas including our NGL fractionation facility in Mont Belvieu, Texas. NGLs originating on the Mid-America Pipeline System are the primary source of throughput for the Seminole Pipeline.
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The Dixie Pipeline extends from southeast Texas and Louisiana to markets in the southeastern U.S. and transports propane and other NGLs. Propane supplies transported on this system primarily originate from southeast Texas, south Louisiana and Mississippi. This system operates in seven states: Texas, Louisiana, Mississippi, Alabama, Georgia, South Carolina and North Carolina and is connected to eight non-regulated propane terminals that we own and operate.
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The Chaparral NGL System transports NGLs from natural gas processing plants in West Texas and New Mexico to Mont Belvieu, Texas. This system consists of the 831-mile Chaparral pipeline and the 180-mile Quanah pipeline. As noted in the preceding table, interstate and intrastate transportation services provided by the Chaparral pipeline are regulated; however, transportation services provided by the Quanah pipeline are non-regulated.
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The Louisiana Pipeline System is a network of NGL pipelines located in southern Louisiana. This system transports NGLs originating in Louisiana and Texas to refineries and petrochemical plants located along the Mississippi River corridor in southern Louisiana. This system also provides transportation services for our natural gas processing plants, NGL fractionators and other assets located in Louisiana. Originating from a central point in Henry, Louisiana, pipelines extend westward to Lake Charles, Louisiana, northward to an interconnect with the Dixie Pipeline at Breaux Bridge, Louisiana and eastward in Louisiana, where our Promix, Norco and Tebone NGL fractionation and Sorrento storage facilities are located.
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The Skelly-Belvieu Pipeline transports mixed NGLs from Skellytown, Texas to Mont Belvieu, Texas. The Skelly-Belvieu Pipeline receives NGLs through a pipeline interconnect with our Mid-America Pipeline System in Skellytown, Texas.
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The Promix NGL Gathering System gathers mixed NGLs from natural gas processing plants in southern Louisiana for delivery to our Promix NGL fractionator.
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The Houston Ship Channel pipeline system connects our Mont Belvieu, Texas facilities with our Houston Ship Channel import/export terminals and various third party petrochemical plants, refineries and other pipelines located along the Houston Ship Channel.
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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 Panola Pipeline transports mixed NGLs from northeast Texas near Carthage in Panola County to Mont Belvieu, Texas. The Panola Pipeline supports the Haynesville and Cotton Valley oil and gas production areas.
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The Lou-Tex NGL Pipeline system transports NGLs and refinery grade propylene between the Louisiana and Texas markets.
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Net Usable
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Storage
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Capacity
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Storage Capacity by State
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(MMBbls)
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Texas (1)
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123.6
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Louisiana
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12.9
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Kansas
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8.6
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Mississippi
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5.1
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Others (2)
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8.9
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Total net usable storage capacity (3)
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159.1
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(1) The amount shown for Texas includes 35 underground NGL, petrochemical and refined products storage caverns with an aggregate working capacity of approximately 100 MMBbls located in Mont Belvieu, Texas.
(2) Includes storage capacity at our facilities in Alabama, Arizona, California, Georgia, Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Nevada, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina and Wisconsin.
(3) Our underground storage caverns and above ground storage tanks have an aggregate 159.1 MMBbls of net usable storage capacity. Our aggregate net usable storage capacity includes 21.3 MMBbls held under long-term operating leases at facilities located in Indiana, Kansas, Louisiana and Texas. Approximately 1.5 MMBbls of our net usable storage capacity in Louisiana is held indirectly through our equity method investment in Promix. The remainder of our NGL underground storage caverns and above ground storage tanks are wholly owned.
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Our
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Net Plant
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Total Plant
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Ownership
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Capacity
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Capacity
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Description of Asset
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Location
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Interest
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(MBPD) (1)
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(MBPD)
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NGL fractionation facilities:
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Mont Belvieu (six units) (2)
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Texas
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Various (3)
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433
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485
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Shoup and Armstrong
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Texas
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100.0%
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98
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98
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Hobbs
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Texas
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100.0%
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75
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75
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Norco
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Louisiana
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100.0%
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75
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75
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Promix
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Louisiana
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50.0% (4)
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73
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145
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BRF
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Louisiana
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32.2% (5)
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19
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60
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Tebone
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Louisiana
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56.2% (6)
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17
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30
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Todhunter
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Ohio
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100.0%
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3
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3
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Total plant fractionation capacities
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793
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971
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(1) The approximate net plant capacity does not necessarily correspond to our ownership interest in each facility. It is based on a variety of factors such as the level of volumes an owner processes at the facility and its ownership interest in the facility.
(2) There are six NGL fractionators located at our Mont Belvieu, Texas facility. Our sixth NGL fractionator commenced commercial operations at this facility in November 2012.
(3) We proportionately consolidate our 75% undivided interest in four of the NGL fractionators located at our Mont Belvieu, Texas facility. The remaining two units are wholly owned.
(4) Our ownership interest in the Promix fractionator is held indirectly through our equity method investment in Promix.
(5) Our ownership interest in the BRF fractionator is held indirectly through our equity method investment in Baton Rouge Fractionators LLC ("BRF").
(6) We proportionately consolidate our undivided interest in the Tebone fractionator.
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Our Mont Belvieu NGL fractionation facility is located in Mont Belvieu, Texas, which is a key hub of the NGL industry. This facility fractionates mixed NGLs from several major NGL supply basins in North America, including the Mid-Continent, Permian Basin, San Juan Basin, Rocky Mountains, East Texas and the Gulf Coast. In early November 2012, construction of our sixth NGL fractionator at Mont Belvieu was completed and it commenced operations. This plant is supported by long-term customer commitments and has a capacity of approximately 85 MBPD. Completion of this plant increased the total NGL fractionation capacity at our Mont Belvieu complex to approximately 485 MBPD.
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Our Shoup and Armstrong fractionators process mixed NGLs supplied by our South Texas natural gas processing plants. Purity NGL products from the Shoup and Armstrong fractionators are transported to local markets in the Corpus Christi area and also to Mont Belvieu, Texas using our South Texas NGL Pipeline System.
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Our Hobbs NGL fractionator is located in Gaines County, Texas, where it serves demand for NGLs in West Texas, New Mexico, California and northern Mexico. The Hobbs fractionator receives mixed NGLs from several major supply basins, including Mid-Continent, Permian Basin, San Juan Basin and the Rocky Mountains. The facility is located at the interconnect of our Mid-America Pipeline System and Seminole Pipeline, thus providing us the flexibility to supply the nation's largest NGL hub at Mont Belvieu, Texas as well as access to the second-largest NGL hub at Conway, Kansas.
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Our Norco NGL fractionator receives mixed NGLs via pipeline from refineries and natural gas processing plants located in southern Louisiana and along the Mississippi and Alabama Gulf Coast, including from our Pascagoula, Venice and Toca facilities.
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The Promix NGL fractionator receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast, including from our Neptune, Burns Point and Pascagoula facilities. In addition to the Promix NGL Gathering System (described previously), Promix owns three NGL storage caverns and a barge loading facility that are important to its operations. Promix leases a fourth NGL storage cavern.
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The BRF fractionator receives mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana.
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Approximate
Net Capacity
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Our
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Usable
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Ownership
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Length
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Pipelines
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Storage
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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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(MMcf/d)
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(Bcf)
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Onshore natural gas pipelines and related storage assets:
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Texas Intrastate System (1)
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Texas
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Various (2)
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8,459
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6,640
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12.9
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Acadian Gas System (1)
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Louisiana
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100.0% (3)
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1,323
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3,100
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1.3
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Jonah Gathering System
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Wyoming
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100.0%
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924
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2,550
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--
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San Juan Gathering System
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New Mexico, Colorado
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100.0%
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6,170
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1,750
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--
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Piceance Basin Gathering System
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Colorado
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100.0%
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190
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1,600
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--
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White River Hub (4)
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Colorado
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50.0% (5)
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10
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1,500
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--
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Haynesville Gathering Systems
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Louisiana, Texas
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100.0%
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314
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1,300
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--
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Fairplay Gathering System
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Texas
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100.0%
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250
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285
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--
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Carlsbad Gathering System
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Texas, New Mexico
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100.0%
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953
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220
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--
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Indian Springs Gathering System
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Texas
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80.0% (6)
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199
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160
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--
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Delmita Gathering System
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Texas
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100.0%
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239
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145
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--
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South Texas Gathering System
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Texas
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100.0%
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648
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143
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--
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Big Thicket Gathering System (7)
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Texas
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100.0%
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253
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60
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--
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Total
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19,932
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14.2
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(1) Intrastate and interstate-sourced volumes transported by these systems are regulated by governmental agencies.
(2) Of the 8,459 miles comprising the Texas Intrastate System, we lease 265 miles from a third party. We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,262 miles of pipeline. Our Wilson natural gas storage facility consists of five underground salt dome natural gas storage caverns with 12.9 Bcf of usable storage capacity, four of which (comprising 6.9 Bcf of usable capacity) are held under an operating lease that expires in January 2028. The remainder of our Texas Intrastate System is wholly owned.
(3) The Acadian Gas System is wholly owned except for an underground salt dome natural gas storage facility that we hold under an operating lease that expires in December 2018.
(4) Interstate volumes at this facility are regulated by governmental agencies.
(5) Our ownership interest in the White River Hub facility is held indirectly through our equity method investment in White River Hub, LLC ("White River Hub").
(6) We proportionately consolidate our undivided interest in the Indian Springs Gathering System.
(7) Intrastate volumes transported by this pipeline are regulated by governmental agencies.
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§
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The Texas Intrastate System is comprised of the 7,070-mile Enterprise Texas pipeline system, the 632-mile Channel pipeline system, the 630-mile Waha gathering system and the 127-mile TPC Offshore gathering
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system. The Wilson natural gas storage facility, which is an important part of the Texas Intrastate System, is comprised of a network of underground salt dome storage caverns located in Wharton County, Texas.
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§
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The Acadian Gas System transports, stores and markets natural gas in Louisiana. The Acadian Gas System is comprised of the 587-mile Cypress pipeline, 442-mile Acadian pipeline, 268-mile Haynesville Extension and 26-mile Enterprise Pelican pipeline. The Acadian Gas System includes a leased underground salt dome natural gas storage cavern located at Napoleonville, Louisiana. The Acadian Gas System links natural gas supplies from Louisiana (e.g., from Haynesville Shale supply basin) and offshore Gulf of Mexico developments with gas distribution companies, electric generation plants and industrial customers located primarily in the Baton Rouge – New Orleans – Mississippi River corridor.
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The Jonah Gathering System is located in the Greater Green River Basin of southwest Wyoming. This system gathers natural gas from the Jonah and Pinedale supply fields for delivery to regional natural gas processing plants, including our Pioneer facilities, for ultimate delivery into major interstate pipelines.
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§
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The San Juan Gathering System serves producers in the San Juan Basin of northern New Mexico and southern Colorado. This system gathers natural gas from production wells located in the San Juan Basin and delivers the natural gas either directly into major interstate pipelines or to regional processing and treating plants, including our Chaco processing facility and Val Verde treating plant located in New Mexico, for ultimate delivery into major interstate pipelines.
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The Piceance Basin Gathering System consists of a network of gathering pipelines located in the Piceance Basin of northwestern Colorado. The Piceance Basin Gathering System gathers natural gas throughout the Piceance Basin to our Meeker natural gas processing complex for ultimate delivery into the White River Hub and other major interstate pipelines.
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§
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The White River Hub is a natural gas hub facility serving producers in the Piceance Basin of northwest Colorado. The facility enables producers to access six interstate natural gas pipelines and has a gross throughput capacity of 3 Bcf/d of natural gas.
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The Haynesville Gathering Systems consist of the 190-mile State Line gathering system, the 78-mile Southeast Mansfield gathering system and the 46-mile Southeast Stanley gathering system. Our Haynesville Gathering Systems gather 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 several downstream markets including the Haynesville Extension of our Acadian Gas System.
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The Fairplay Gathering System gathers natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations within Panola and Rusk Counties in East Texas. This system is expected to extend our asset base through potential future interconnects with our Texas Intrastate System, support deliveries of NGLs into our Panola liquids pipeline and further to our fractionation, storage and distribution complex in Mont Belvieu, Texas.
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§
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The Carlsbad Gathering System gathers natural gas from the Permian Basin region of Texas and New Mexico for delivery to natural gas processing plants, including our Chaparral and Carlsbad plants, as well as delivery into the El Paso Natural Gas and Transwestern pipelines.
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Our
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Pipeline
|
|
|
|
Ownership
|
Length
|
Description of Asset
|
Location(s)
|
Interest
|
(Miles)
|
|
Crude oil pipelines:
|
|
|
|
|
|
Seaway Pipeline (1)
|
Texas, Oklahoma
|
50.0% (2)
|
567
|
|
Red River System (1)
|
Texas, Oklahoma
|
100.0%
|
1,859
|
|
South Texas Crude Oil Pipeline System (3)
|
Texas
|
100.0%
|
1,119
|
|
West Texas System (1)
|
Texas, New Mexico
|
100.0%
|
772
|
|
Basin Pipeline (1)
|
Texas, New Mexico, Oklahoma
|
13.0% (4)
|
519
|
|
Other (three systems) (5)
|
Texas, New Mexico
|
100.0%
|
230
|
|
Total miles
|
|
|
5,066
|
|
|
|
|
|
(1) Interstate and intrastate transportation services provided by these liquids pipelines are regulated by governmental agencies.
(2) Our ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Pipeline Company LLC ("Seaway").
(3) Intrastate transportation services provided by these liquids pipelines are regulated by governmental agencies.
(4) We proportionately consolidate our undivided interest in the Basin Pipeline.
(5) Includes our Azelea and Sharon Ridge crude oil gathering systems located in Texas and Mesquite pipeline in New Mexico.
|
§
|
The Seaway Pipeline connects the Cushing, Oklahoma hub with markets in Southeast Texas. The Seaway Pipeline is comprised of the Longhaul 30-inch System, the Freeport System and the Texas City System. The Longhaul 30-inch System includes an approximately 500-mile, 30-inch diameter pipeline that provides north-to-south transportation of crude oil from the Cushing hub to Seaway's Jones Creek terminal, which is near Freeport, Texas, and an Enterprise terminal located near Katy, Texas. The Cushing hub is a major industry trading hub and price settlement point for West Texas Intermediate on the New York Mercantile Exchange.
|
§
|
The Red River System transports crude oil from North Texas to southern Oklahoma for delivery to either two local refineries or pipeline interconnects for further transportation to Cushing, Oklahoma. The Red River System is connected to 1.2 MMBbls of crude oil storage capacity that we own and operate.
|
§
|
The South Texas Crude Oil Pipeline System transports crude oil originating in South Texas, including production from the Eagle Ford Shale supply basin, to refineries in the Greater Houston area. In June 2012, we announced that the Eagle Ford expansion of our South Texas Crude Oil Pipeline System commenced operations. This pipeline expansion, which has a crude oil transportation capacity of 350 MBPD, allows us to serve growing production areas in the Eagle Ford Shale supply basin. The new pipeline originates at our Lyssy station in Karnes County, Texas and extends 147 miles to Sealy, Texas and includes 2.4 MMBbls of crude oil storage, including 0.8 MMBbls in Karnes County, Texas, 0.4 MMBbls in Gonzales County, Texas and 1.2 MMBbls at Sealy. Crude oil supplies arriving at Sealy on the new pipeline are being delivered to Houston area refiners through affiliate and third party owned pipelines. In addition, shippers have access to our new ECHO crude oil storage terminal.
|
§
|
The West Texas System connects crude oil gathering systems in West Texas and southeast New Mexico to our terminal facility in Midland, Texas. The West Texas System is connected to 0.4 MMBbls of crude oil storage capacity that we own and operate.
|
§
|
The Basin Pipeline transports crude oil from the Permian Basin in West Texas and southern New Mexico to Cushing, Oklahoma. The Basin Pipeline includes 5 MMBbls of crude oil storage capacity (or 0.8 MMBbls net to our ownership interest).
|
|
|
|
|
Net Usable
|
|
|
|
Our
|
Storage
|
|
|
|
Ownership
|
Capacity
|
Description of Asset
|
Location(s)
|
Interest
|
(MMBbls)
|
|
Crude oil terminals:
|
|
|
|
|
|
ECHO terminal
|
Texas
|
100.0%
|
0.5
|
|
Cushing terminal
|
Oklahoma
|
100.0%
|
3.1
|
|
Midland terminal
|
Texas
|
100.0%
|
1.5
|
|
Total capacity
|
|
|
5.1
|
§
|
The ECHO terminal, or Enterprise Crude Houston storage terminal, is located in southeast Houston, Texas and provides our customers with access to major refiners located in the Houston and Texas City area representing more than 2 MMBPD of refining capacity. The ECHO terminal also has connections to marine facilities that provide connectivity to any refinery on the U.S. Gulf Coast. We developed the ECHO terminal to support the expansion of our South Texas Crude Oil Pipeline System and the reversal of the Seaway Pipeline. We own and operate the ECHO terminal.
|
§
|
The Cushing terminal provides crude oil storage, pumpover and trade documentation services. Our terminal in Cushing, Oklahoma has 19 above-ground storage tanks with aggregate crude oil storage capacity of 3.1 MMBbls.
|
§
|
The Midland terminal provides crude oil storage, pumpover and trade documentation services. The Midland, Texas terminal has an aggregate storage capacity of 1.5 MMBbls through the use of 12 above-ground storage tanks.
|
|
|
Our
|
Pipeline
|
Approximate
|
|
|
Ownership
|
Length
|
Net Capacity
|
Description of Asset
|
Interest
|
(Miles)
|
(MMcf/d) (1)
|
|
Offshore natural gas pipelines:
|
|
|
|
|
|
Independence Trail
|
100.0%
|
135
|
1,000
|
|
Viosca Knoll Gathering System
|
100.0%
|
137
|
600
|
|
High Island Offshore System
|
100.0%
|
287
|
500
|
|
Falcon Natural Gas Pipeline
|
100.0%
|
14
|
400
|
|
Green Canyon Laterals
|
Various (2)
|
54
|
343
|
|
Anaconda Gathering System
|
100.0%
|
183
|
300
|
|
Manta Ray Offshore Gathering System
|
25.7% (3)
|
220
|
205
|
|
Nautilus System
|
25.7% (3)
|
101
|
154
|
|
Nemo Gathering System
|
33.9% (4)
|
24
|
102
|
|
VESCO Gathering System
|
13.1% (5)
|
125
|
60
|
Total miles
|
|
1,280
|
|
|
|
|
|
|
|
(1) Amounts presented are net to our ownership interest.
(2) We proportionately consolidate our undivided interests, which range from 2.7% to 33.3%, in 47 miles of the Green Canyon Lateral pipelines. The remainder of the laterals are wholly owned.
(3) Our ownership interests in the Manta Ray Offshore Gathering System and the Nautilus System are held indirectly through our equity method investment in Neptune Pipeline Company, L.L.C. ("Neptune").
(4) Our ownership interest in the Nemo Gathering System is held indirectly through our cost method investment in Nemo Gathering Company, LLC ("Nemo").
(5) Our ownership interest in the VESCO Gathering System is held indirectly through our equity method investment in VESCO. This system is important to our natural gas processing operations; therefore, our equity method investment in VESCO is accounted for under our NGL Pipelines & Services business segment.
|
§
|
The Independence Trail natural gas pipeline transports natural gas that originates at our Independence Hub platform and at a pipeline interconnect downstream of our Independence Hub platform. Our Independence Trail pipeline delivers natural gas to the Tennessee Gas Pipeline at a pipeline interconnect on our West Delta 68 platform. Natural gas transported on the Independence Trail pipeline originates from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.
|
§
|
The Viosca Knoll Gathering System gathers natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico for delivery to several major interstate pipelines, including the High Point Gas Transmission, Transco, Dauphin Island Gathering System, Tennessee Gas Pipeline and Destin Pipelines.
|
§
|
The High Island Offshore System ("HIOS") transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of Mexico to the ANR pipeline system and Tennessee Gas Pipeline. HIOS includes 201 miles of pipeline and eight pipeline junction and service platforms that are regulated by the FERC. In addition, this system includes the 86-mile East Breaks Gathering System that connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25.
|
§
|
The Falcon Natural Gas Pipeline transports natural gas processed at our Falcon Nest platform to a connection with the Central Texas Gathering System located at the Brazos Addition Block 133 platform.
|
§
|
The Green Canyon Laterals represent a collection of small diameter pipelines that gather natural gas for delivery to HIOS and various other downstream pipelines.
|
§
|
The Anaconda Gathering System gathers natural gas from producing fields located in the Green Canyon area of the Gulf of Mexico for delivery to our Nautilus System.
|
§
|
The Manta Ray Offshore Gathering System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for delivery to numerous downstream pipelines, including our Nautilus System.
|
§
|
The Nautilus System connects our Anaconda Gathering System and Manta Ray Offshore Gathering System to our Neptune natural gas processing plant located in south Louisiana.
|
§
|
The Nemo Gathering System gathers natural gas from producing fields located in the Green Canyon area of the Gulf of Mexico for delivery to an interconnect with our Manta Ray Offshore Gathering System.
|
§
|
The VESCO Gathering System gathers natural gas from certain offshore developments for delivery to the Venice natural gas processing plant in south Louisiana.
|
|
|
Our
|
|
Approximate
|
|
|
Ownership
|
Length
|
Net Capacity
|
Description of Asset
|
Interest
|
(Miles)
|
(MBPD) (1)
|
|
Offshore crude oil pipelines:
|
|
|
|
|
|
Cameron Highway Oil Pipeline
|
50.0% (2)
|
374
|
250
|
|
Shenzi Oil Pipeline
|
100.0%
|
83
|
230
|
|
Poseidon Oil Pipeline System
|
36.0% (3)
|
367
|
155
|
|
Allegheny Oil Pipeline
|
100.0%
|
40
|
140
|
|
Marco Polo Oil Pipeline
|
100.0%
|
37
|
120
|
|
Constitution Oil Pipeline
|
100.0%
|
67
|
80
|
|
Typhoon Oil Pipeline
|
100.0%
|
17
|
80
|
|
Tarantula Oil Pipeline
|
100.0%
|
4
|
30
|
Total miles
|
|
989
|
|
|
|
|
|
|
|
(1) Amounts presented are net to our ownership interest.
(2) Our ownership interest in the Cameron Highway Oil Pipeline is held indirectly through our equity method investment in Cameron Highway Oil Pipeline Company ("Cameron Highway").
(3) Our ownership interest in the Poseidon Oil Pipeline System is held indirectly through our equity method investment in Poseidon Oil Pipeline Company, L.L.C. ("Poseidon").
|
§
|
The Cameron Highway Oil Pipeline transports crude oil production from deepwater areas of the Gulf of Mexico, primarily the Green Canyon area, for delivery to refineries and terminals in southeast Texas. This system includes two pipeline junction platforms.
|
§
|
The Shenzi Oil Pipeline gathers crude oil production from the Shenzi production field located in the Green Canyon area of the Gulf of Mexico for delivery to both our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.
|
§
|
The Poseidon Oil Pipeline System transports crude oil production from the outer continental shelf and deepwater areas of the Gulf of Mexico offshore Louisiana to onshore facilities in south Louisiana. This system includes one pipeline junction platform.
|
§
|
The Allegheny Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.
|
§
|
The Marco Polo Oil Pipeline transports crude oil from our Marco Polo oil platform to an interconnect with our Allegheny Oil Pipeline in Green Canyon Block 164.
|
§
|
The Constitution Oil Pipeline gathers crude oil from the Constitution, Caesar Tonga and Ticonderoga production fields located in the Green Canyon area of the Gulf of Mexico for delivery to either our Cameron Highway Oil Pipeline or Poseidon Oil Pipeline System.
|
|
|
Our
|
Water
|
Approximate
Net Capacity (1)
|
|
|
|
Ownership
|
Depth
|
Natural Gas
|
Crude Oil
|
Description of Asset
|
Interest
|
(Feet)
|
(MMcf/d)
|
(MBPD)
|
|
Offshore hub platforms:
|
|
|
|
|
|
|
Independence Hub
|
80.0% (2)
|
8,000
|
800
|
N/A
|
|
Marco Polo
|
50.0% (3)
|
4,300
|
150
|
60
|
|
Viosca Knoll 817
|
100.0%
|
671
|
145
|
5
|
|
Garden Banks 72
|
50.0% (4)
|
518
|
113
|
18
|
|
East Cameron 373
|
100.0%
|
441
|
195
|
3
|
|
Falcon Nest
|
100.0%
|
389
|
400
|
3
|
|
|
|
|
|
|
(1) Amounts presented are net to our ownership interest.
(2) We own an 80% consolidated interest in the Independence Hub platform through our majority owned subsidiary, Independence Hub, LLC.
(3) Our ownership interest in the Marco Polo platform is held indirectly through our equity method investment in Deepwater Gateway, L.L.C. ("Deepwater Gateway").
(4) We proportionately consolidate our undivided interest in the Garden Banks 72 platform.
|
§
|
The Independence Hub platform is located in Mississippi Canyon Block 920. This platform processes natural gas gathered from deepwater production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.
|
§
|
The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of Mexico.
|
§
|
The Viosca Knoll 817 platform is centrally located on our Viosca Knoll Gathering System. This platform primarily serves as a base for gathering deepwater production in the Viosca Knoll area, including the Ram Powell development.
|
§
|
The Garden Banks 72 platform serves as a base for gathering deepwater production from the Garden Banks area of the Gulf of Mexico. This platform also serves as a junction platform for our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.
|
§
|
The East Cameron 373 platform processes production from the Garden Banks and East Cameron areas of the Gulf of Mexico.
|
§
|
The Falcon Nest platform, which is located in the Mustang Island East area of the Gulf of Mexico, processes natural gas from the Falcon field.
|
|
|
|
Our
|
Net Plant
|
Total Plant
|
|
|
|
Ownership
|
Capacity
|
Capacity
|
Description of Asset
|
Location(s)
|
Interest
|
(MBPD)
|
(MBPD)
|
|
Propylene fractionation facilities:
|
|
|
|
||
|
Mont Belvieu (six units)
|
Texas
|
Various (1)
|
73
|
87
|
|
BRPC (one unit)
|
Louisiana
|
30.0% (2)
|
7
|
23
|
|
Total capacity
|
|
|
80
|
110
|
|
|
|
|
|
|
(1) We proportionately consolidate our 66.7% undivided interest in three of the Mont Belvieu propylene fractionators, which have an aggregate 41 MBPD of total plant capacity. The remaining three propylene fractionators at our Mont Belvieu facility are wholly owned.
(2) Our ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC ("BRPC").
|
|
|
|
Ownership
|
Length
|
Description of Asset
|
Location(s)
|
Interest
|
(Miles)
|
|
Petrochemical pipelines:
|
|
|
|
|
|
Lou-Tex and Sabine Propylene
|
Texas, Louisiana
|
100.0%
|
287
|
|
Texas City RGP Gathering System
|
Texas
|
100.0%
|
164
|
|
North Dean Pipeline System
|
Texas
|
100.0%
|
149
|
|
Propylene Splitter PGP Distribution System
|
Texas
|
100.0%
|
33
|
|
Lake Charles PGP Pipeline
|
Louisiana
|
50.0% (1)
|
26
|
|
La Porte PGP Pipeline
|
Texas
|
50.0% (2)
|
17
|
|
Total miles
|
|
|
676
|
|
|
|
|
|
(1) We proportionately consolidate our undivided interest in the Lake Charles PGP Pipeline.
(2) Our ownership interest in the La Porte PGP Pipeline is held indirectly through our equity method investments in La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C.
|
|
|
|
|
|
Net Usable
|
|
|
|
Our
|
|
Storage
|
|
|
|
Ownership
|
Length
|
Capacity
|
Description of Asset
|
Location(s)
|
Interest
|
(Miles)
|
(MMBbls)
|
|
Refined products pipelines and terminals:
|
|
|
|
||
|
TE Products Pipeline (1,2)
|
Texas to Midwest and Northeast U.S.
|
100.0%
|
4,381
|
18.4
|
|
Centennial Pipeline (2)
|
Texas to central Illinois
|
50.0% (3)
|
795
|
1.2
|
|
Other terminals (4)
|
Alabama, Mississippi, Texas
|
100.0%
|
n/a
|
1.2
|
|
Total
|
|
|
5,176
|
20.8
|
|
|
|
|
|
|
(1) In addition to 18.4 MMBbls of refined products usable storage capacity, we have 4.9 MMBbls of NGL usable storage capacity that is used to support operations on our TE Products Pipeline. Our NGL storage and terminal assets are accounted for under our NGL Pipelines & Services business segment.
(2) Interstate and intrastate transportation services provided by the TE Products Pipeline and interstate transportation services provided by the Centennial Pipeline are regulated by governmental agencies.
(3) Our ownership interest in the Centennial Pipeline is held indirectly through our equity method investment in Centennial.
(4) Includes product distribution and marketing terminals located in Aberdeen, Mississippi and Boligee, Alabama having a usable storage capacity of 0.1 MMBbls and 0.5 MMBbls, respectively, and a storage terminal located in Pasadena, Texas having a usable storage capacity of 0.6 MMBbls.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Refined products transportation (MBPD)
|
383
|
429
|
511
|
|||||||||
Petrochemical transportation (MBPD)
|
101
|
121
|
122
|
|||||||||
NGL transportation (MBPD)
|
66
|
92
|
101
|
§
|
The TE Products Pipeline is a 4,381-mile pipeline system comprised of 4,063 miles of interstate pipelines and 318 miles of intrastate Texas pipelines. Refined products and NGLs are transported from the upper Texas Gulf Coast through two parallel pipelines that extend to Seymour, Indiana. From Seymour, segments of the TE Products Pipeline extend to the Chicago, Illinois; Lima, Ohio; Selkirk, New York; and Philadelphia (Sinking Spring), Pennsylvania areas. The TE Products Pipeline east of Todhunter, Ohio is
|
|
primarily dedicated to NGL transportation services. Products are delivered to various locations along the system including to terminals owned either by us or third parties and to various connecting pipelines.
|
§
|
The Centennial Pipeline is a refined products pipeline system that extends from Texas to Illinois. The Centennial Pipeline extends from an origination facility located on our TE Products Pipeline in Beaumont, Texas, to Bourbon, Illinois. Centennial owns a refined products storage terminal located near Creal Springs, Illinois with a gross storage capacity of 2.3 MMBbls.
|
Class of Equipment
|
Number in Class
|
Capacity/
Horsepower
(as indicated by sign) (1)
|
Inland marine transportation assets:
|
|
|
Barges
|
19
|
< 25,000 bbls
|
Barges
|
104
|
> 25,000 bbls
|
Tow boats
|
37
|
< 2,000 hp
|
Tow boats
|
21
|
≥ 2,000 hp
|
Offshore marine transportation assets:
|
|
|
Ocean-certified tank barges
|
8
|
≥ 20,000 bbls
|
Tow boats
|
3
|
< 2,000 hp
|
Tow boats
|
3
|
> 2,000 hp
|
|
|
|
(1) As used in this table, references to "bbls" means barrels and "hp" means horsepower.
|
§
|
Ten states in the Northeast and Mid-Atlantic region signed a compact and have implemented rules to limit carbon dioxide emissions from power plants under the Regional Greenhouse Gas Initiative ("RGGI"), which requires electric generating facilities to purchase emissions allowances corresponding to their respective emissions under a cap-and-trade system. RGGI started its second compliance period (from 2012-2014) under the cap-and-trade program and is currently conducting a state by state evaluation of the efficiency, impacts and economic feasibility of the program.
|
§
|
The California Air Resources Board ("CARB") issued a series of rules under that state's Global Warming Solutions Act, including restrictions on greenhouse gas emissions from industrial sources and regulating the carbon content of fuels. A multi-year, comprehensive program to reduce greenhouse gas emissions was put into effect by the CARB in January 2012.
|
§
|
In November 2010, the New Mexico Environmental Improvement Board adopted new regulations pursuant to state law establishing a greenhouse gas cap-and-trade program to be implemented by the New Mexico Environment Department. However, the cap-and-trade program was repealed in February 2012.
|
§
|
Ethane is primarily used in the petrochemical industry as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. If natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls (and, therefore, the demand for ethane decreases), where gas quality specifications would allow, it may be more profitable for natural gas producers to leave the ethane in a mixed natural gas stream to be burned as fuel than to extract it for sale as an ethylene feedstock.
|
§
|
The demand for propane as a heating fuel is significantly affected by weather conditions. Unusually warm winters could cause the demand for propane to decline significantly and could cause a significant decline in the volumes of propane that we transport.
|
§
|
A reduction in demand for motor gasoline additives may reduce demand for isobutane, which could adversely impact the price of isobutane and reduce our operating margin from selling isobutane.
|
§
|
Propylene is sold to petrochemical companies for a variety of uses, principally for the production of polypropylene. Propylene is subject to rapid and material price fluctuations. Any downturn in the domestic or international economy could cause reduced demand for, and an oversupply of propylene, which could cause a reduction in the volumes of propylene that we sell and transport.
|
§
|
a substantial portion of our cash flow could be dedicated to the payment of principal and interest on our future debt and may not be available for other purposes, including the payment of distributions on our common units and capital expenditures;
|
§
|
credit rating agencies may take a negative view of our consolidated debt level;
|
§
|
covenants contained in our existing and future credit and debt agreements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
|
§
|
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
|
§
|
we may be at a competitive disadvantage relative to similar companies that have less debt; and
|
§
|
we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.
|
§
|
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.
|
§
|
we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits;
|
§
|
we will not receive any material increase in operating cash flows until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;
|
§
|
we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize;
|
§
|
since we are not engaged in the exploration for and development of natural gas reserves, we may not have access to third party estimates of reserves in an area prior to our constructing facilities in the area. As a result, we may construct facilities in an area where the reserves are materially lower than we anticipate;
|
§
|
in those situations where we do rely on third party reserve estimates in making a decision to construct assets, these estimates may prove inaccurate;
|
§
|
the completion or success of our construction project may depend on the completion of a third party construction project (e.g., a downstream crude oil refinery expansion) that we do not control and that may be subject to numerous of its own potential risks, delays and complexities; and
|
§
|
we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.
|
§
|
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.
|
§
|
We contacted the New Mexico Environment Department to self-disclose possible air emission and permit compliance violations at our facilities located in New Mexico. We discovered these matters during an internal compliance audit of these facilities in 2011. We believe that the eventual resolution of these New Mexico matters will result in a monetary sanction of $0.2 million.
|
§
|
The Texas Commission on Environmental Quality ("TCEQ") notified us in the fourth quarter of 2012 that several, existing notices of enforcement issued in connection with air emissions by our Houston-area operations would be combined into one order. We believe that the eventual resolution of this consolidated order will result in penalties or other costs of at least $0.1 million.
|
|
Cash Distribution History
|
|||||||||||||
|
Price Ranges
|
Per
|
Record
|
Payment
|
||||||||||
|
High
|
Low
|
Unit
|
Date
|
Date
|
|||||||||
2011
|
|
|
||||||||||||
1st Quarter
|
$
|
44.35
|
$
|
27.85
|
$
|
0.5975
|
April 29, 2011
|
May 6, 2011
|
||||||
2nd Quarter
|
$
|
43.95
|
$
|
38.67
|
$
|
0.6050
|
July 29, 2011
|
August 10, 2011
|
||||||
3rd Quarter
|
$
|
43.95
|
$
|
36.36
|
$
|
0.6125
|
October 31, 2011
|
November 9, 2011
|
||||||
4th Quarter
|
$
|
46.70
|
$
|
38.01
|
$
|
0.6200
|
January 31, 2012
|
February 9, 2012
|
||||||
2012
|
|
|
||||||||||||
1st Quarter
|
$
|
52.95
|
$
|
45.78
|
$
|
0.6275
|
April 30, 2012
|
May 9, 2012
|
||||||
2nd Quarter
|
$
|
52.94
|
$
|
45.67
|
$
|
0.6350
|
July 31, 2012
|
August 8, 2012
|
||||||
3rd Quarter
|
$
|
54.98
|
$
|
50.78
|
$
|
0.6500
|
October 31, 2012
|
November 8, 2012
|
||||||
4th Quarter
|
$
|
55.38
|
$
|
48.52
|
$
|
0.6600
|
January 31, 2013
|
February 7, 2013
|
|
Maximum
|
|||||||||||||||
|
Total Number of
|
Number of Units
|
||||||||||||||
|
Average
|
Units Purchased
|
That May Yet
|
|||||||||||||
|
Total Number of
|
Price Paid
|
as Part of Publicly
|
Be Purchased
|
||||||||||||
Period
|
Units Purchased
|
per Unit
|
Announced Plans
|
Under the Plans
|
||||||||||||
February 2012 (1)
|
187,343
|
$
|
51.54
|
--
|
--
|
|||||||||||
May 2012 (2)
|
186,048
|
$
|
49.82
|
--
|
--
|
|||||||||||
August 2012 (3)
|
7,942
|
$
|
53.12
|
--
|
--
|
|||||||||||
September 2012 (4)
|
1,087
|
$
|
54.24
|
--
|
--
|
|||||||||||
November 2012 (5)
|
24,236
|
$
|
52.47
|
--
|
--
|
|||||||||||
December 2012 (6)
|
1,585
|
$
|
50.05
|
--
|
--
|
|||||||||||
(1) Of the 632,298 restricted common units that vested in February 2012 and converted to common units, 187,343 units were sold back to us by employees to cover related withholding tax requirements.
(2) Of the 604,054 restricted common units that vested in May 2012 and converted to common units, 186,048 units were sold back to us by employees to cover related withholding tax requirements.
(3) Of the 28,131 restricted common units that vested in August 2012 and converted to common units, 7,942 units were sold back to us by employees to cover related withholding tax requirements.
(4) Of the 4,100 equity-based awards that vested in September 2012 and converted to common units, 1,087 units were sold back to us by employees to cover related withholding tax requirements.
(5) Of the 82,621 equity-based awards that vested in November 2012 and converted to common units, 24,236 units were sold back to us by employees to cover related withholding tax requirements.
(6) Of the 5,000 equity-based awards that vested in December 2012 and converted to common units, 1,585 units were sold back to us by employees to cover related withholding tax requirements.
|
|
For Year Ended December 31,
|
|||||||||||||||||||
|
2012
|
2011
|
2010
|
2009
|
2008
|
|||||||||||||||
Results of operations data: (1)
|
||||||||||||||||||||
Revenues
|
$
|
42,583.1
|
$
|
44,313.0
|
$
|
33,739.3
|
$
|
25,510.9
|
$
|
35,469.6
|
||||||||||
Income from continuing operations
|
$
|
2,428.0
|
$
|
2,088.3
|
$
|
1,383.7
|
$
|
1,140.3
|
$
|
1,145.1
|
||||||||||
Net income
|
$
|
2,428.0
|
$
|
2,088.3
|
$
|
1,383.7
|
$
|
1,140.3
|
$
|
1,145.1
|
||||||||||
Net income attributable to limited partners
|
$
|
2,419.9
|
$
|
2,046.9
|
$
|
320.8
|
$
|
204.1
|
$
|
164.0
|
||||||||||
Earnings per unit: (2)
|
||||||||||||||||||||
Basic
|
$
|
2.81
|
$
|
2.48
|
$
|
1.17
|
$
|
0.99
|
$
|
0.89
|
||||||||||
Diluted
|
$
|
2.71
|
$
|
2.38
|
$
|
1.15
|
$
|
0.99
|
$
|
0.89
|
||||||||||
Other financial data:
|
||||||||||||||||||||
Cash distributions per unit (3)
|
$
|
2.57
|
$
|
2.44
|
$
|
2.27
|
$
|
2.03
|
$
|
1.79
|
||||||||||
|
||||||||||||||||||||
|
As of December 31,
|
|||||||||||||||||||
|
2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||
Financial position data: (1)
|
||||||||||||||||||||
Consolidated assets
|
$
|
35,934.4
|
$
|
34,125.1
|
$
|
31,360.8
|
$
|
27,686.3
|
$
|
25,780.4
|
||||||||||
Consolidated debt (4)
|
$
|
16,201.8
|
$
|
14,529.4
|
$
|
13,563.5
|
$
|
12,427.9
|
$
|
12,714.9
|
||||||||||
Equity (5)
|
$
|
13,296.0
|
$
|
12,219.3
|
$
|
11,900.8
|
$
|
10,473.1
|
$
|
9,759.4
|
||||||||||
Total limited partner units outstanding (6)
|
898.8
|
881.6
|
843.7
|
208.8
|
184.8
|
|||||||||||||||
|
||||||||||||||||||||
(1) In general, our consolidated results of operations and financial position have been impacted by our capital spending program. For information regarding our capital spending program, see "Liquidity and Capital Resources – Capital Spending" under Part II, Item 7 of this annual report.
(2) Earnings per unit amounts for periods prior to the Holdings Merger in November 2010 have been retroactively presented to reflect the 1.5 to one unit-for-unit exchange that occurred under the Holdings Merger. For information regarding our earnings per unit amounts, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
(3) Cash distributions per unit presented for 2009 and 2008 reflect those declared and paid by Holdings. Cash distributions per unit presented for 2010 represent the sum of cash distributions declared and paid by Holdings with respect to the first, second and third quarters of 2010 and the cash distribution declared and paid by Enterprise with respect to the fourth quarter of 2010. Cash distributions per unit for 2012 and 2011 represent those declared and paid by Enterprise with respect to those years. For information regarding our cash distributions, see Note 13 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
(4) Consolidated debt has increased over time as a result of our capital spending program. For information regarding our consolidated debt obligations, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
(5) Consolidated equity has increased over time primarily due to the issuance of limited partner units by Enterprise in connection with acquisitions and its capital spending program. For information regarding our consolidated equity, see Note 13 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
(6) Total units outstanding increased in 2010 in part due to the Holdings Merger in November 2010 and reflects, following the Holdings Merger, the number of Enterprise limited partner common units outstanding. Total units outstanding increased in 2011 in part due to the Duncan Merger in September 2011 and reflects, following the Duncan Merger, the number of Enterprise common units outstanding. Total units outstanding at December 31, 2012, 2011 and 2010 includes the Designated Units issued in connection with the Holdings Merger, which are owned by a privately held affiliate of EPCO that agreed to temporarily waive regular quarterly cash distributions over a five-year period on such units. For information regarding the Designated Units, see Note 1 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Total units outstanding at December 31, 2012, 2011 and 2010 exclude 4.5 million Class B units of Enterprise.
|
/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
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Revenues
|
$
|
42,583.1
|
$
|
44,313.0
|
$
|
33,739.3
|
||||||
Costs and expenses:
|
||||||||||||
Operating costs and expenses:
|
||||||||||||
Cost of sales
|
36,015.5
|
38,292.6
|
28,723.1
|
|||||||||
Other operating costs and expenses
|
2,244.9
|
2,195.4
|
1,825.9
|
|||||||||
Depreciation, amortization and accretion
|
1,061.7
|
958.7
|
936.3
|
|||||||||
Gains attributable to disposal of assets
|
(17.6
|
)
|
(156.0
|
)
|
(44.4
|
)
|
||||||
Non-cash asset impairment charges
|
63.4
|
27.8
|
8.4
|
|||||||||
Total operating costs and expenses
|
39,367.9
|
41,318.5
|
31,449.3
|
|||||||||
General and administrative costs
|
170.3
|
181.8
|
204.8
|
|||||||||
Total costs and expenses
|
39,538.2
|
41,500.3
|
31,654.1
|
|||||||||
Equity in income of unconsolidated affiliates
|
64.3
|
46.4
|
62.0
|
|||||||||
Operating income
|
3,109.2
|
2,859.1
|
2,147.2
|
|||||||||
Interest expense
|
(771.8
|
)
|
(744.1
|
)
|
(741.9
|
)
|
||||||
Other, net
|
73.4
|
0.5
|
4.5
|
|||||||||
Benefit from (provision for) income taxes
|
17.2
|
(27.2
|
)
|
(26.1
|
)
|
|||||||
Net income
|
2,428.0
|
2,088.3
|
1,383.7
|
|||||||||
Net income attributable to noncontrolling interests
|
(8.1
|
)
|
(41.4
|
)
|
(1,062.9
|
)
|
||||||
Net income attributable to limited partners
|
$
|
2,419.9
|
$
|
2,046.9
|
$
|
320.8
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
NGL Pipelines & Services:
|
||||||||||||
Sales of NGLs and related products
|
$
|
14,218.5
|
$
|
16,724.6
|
$
|
13,449.4
|
||||||
Midstream services
|
949.9
|
758.7
|
753.1
|
|||||||||
Total
|
15,168.4
|
17,483.3
|
14,202.5
|
|||||||||
Onshore Natural Gas Pipelines & Services:
|
||||||||||||
Sales of natural gas
|
2,395.4
|
2,866.5
|
2,928.7
|
|||||||||
Midstream services
|
957.2
|
863.7
|
772.9
|
|||||||||
Total
|
3,352.6
|
3,730.2
|
3,701.6
|
|||||||||
Onshore Crude Oil Pipelines & Services:
|
||||||||||||
Sales of crude oil
|
17,548.7
|
15,962.6
|
10,710.4
|
|||||||||
Midstream services
|
113.0
|
98.5
|
84.4
|
|||||||||
Total
|
17,661.7
|
16,061.1
|
10,794.8
|
|||||||||
Offshore Pipelines & Services:
|
||||||||||||
Sales of natural gas
|
0.4
|
1.1
|
1.3
|
|||||||||
Sales of crude oil
|
3.3
|
9.4
|
9.5
|
|||||||||
Midstream services
|
187.8
|
245.5
|
299.9
|
|||||||||
Total
|
191.5
|
256.0
|
310.7
|
|||||||||
Petrochemical & Refined Products Services:
|
||||||||||||
Sales of petrochemicals and refined products
|
5,470.9
|
6,000.6
|
4,009.1
|
|||||||||
Midstream services
|
738.0
|
781.8
|
720.6
|
|||||||||
Total
|
6,208.9
|
6,782.4
|
4,729.7
|
|||||||||
Total consolidated revenues
|
$
|
42,583.1
|
$
|
44,313.0
|
$
|
33,739.3
|
|
Polymer
|
Refinery
|
||||||||||||||||||||||||||||||||||
|
Natural
|
Normal
|
Natural
|
Grade
|
Grade
|
|||||||||||||||||||||||||||||||
|
Gas,
|
Ethane,
|
Propane,
|
Butane,
|
Isobutane,
|
Gasoline,
|
Propylene,
|
Propylene,
|
Crude Oil,
|
|||||||||||||||||||||||||||
|
$/MMBtu
|
$/gallon
|
$/gallon
|
$/gallon
|
$/gallon
|
$/gallon
|
$/pound
|
$/pound
|
$/barrel
|
|||||||||||||||||||||||||||
|
(1) |
|
(2) |
|
(2) |
|
(2) |
|
(2) |
|
(2) |
|
(3) |
|
(3) |
|
(4) |
|
||||||||||||||||||
2010 Averages
|
$
|
4.39
|
$
|
0.60
|
$
|
1.16
|
$
|
1.50
|
$
|
1.58
|
$
|
1.84
|
$
|
0.61
|
$
|
0.48
|
$
|
79.53
|
||||||||||||||||||
2011 by quarter:
|
||||||||||||||||||||||||||||||||||||
1st Quarter
|
$
|
4.11
|
$
|
0.66
|
$
|
1.37
|
$
|
1.75
|
$
|
1.85
|
$
|
2.27
|
$
|
0.76
|
$
|
0.68
|
$
|
94.10
|
||||||||||||||||||
2nd Quarter
|
$
|
4.32
|
$
|
0.78
|
$
|
1.49
|
$
|
1.87
|
$
|
2.02
|
$
|
2.48
|
$
|
0.89
|
$
|
0.79
|
$
|
102.56
|
||||||||||||||||||
3rd Quarter
|
$
|
4.20
|
$
|
0.78
|
$
|
1.54
|
$
|
1.88
|
$
|
2.09
|
$
|
2.37
|
$
|
0.78
|
$
|
0.67
|
$
|
89.76
|
||||||||||||||||||
4th Quarter
|
$
|
3.54
|
$
|
0.86
|
$
|
1.44
|
$
|
1.89
|
$
|
2.26
|
$
|
2.24
|
$
|
0.59
|
$
|
0.44
|
$
|
94.06
|
||||||||||||||||||
2011 Averages
|
$
|
4.04
|
$
|
0.77
|
$
|
1.46
|
$
|
1.85
|
$
|
2.06
|
$
|
2.34
|
$
|
0.76
|
$
|
0.64
|
$
|
95.12
|
||||||||||||||||||
2012 by quarter:
|
||||||||||||||||||||||||||||||||||||
1st Quarter
|
$
|
2.72
|
$
|
0.56
|
$
|
1.26
|
$
|
1.93
|
$
|
2.04
|
$
|
2.39
|
$
|
0.69
|
$
|
0.60
|
$
|
102.93
|
||||||||||||||||||
2nd Quarter
|
$
|
2.21
|
$
|
0.40
|
$
|
0.98
|
$
|
1.62
|
$
|
1.75
|
$
|
2.05
|
$
|
0.66
|
$
|
0.51
|
$
|
93.49
|
||||||||||||||||||
3rd Quarter
|
$
|
2.80
|
$
|
0.34
|
$
|
0.89
|
$
|
1.44
|
$
|
1.62
|
$
|
2.01
|
$
|
0.51
|
$
|
0.37
|
$
|
92.22
|
||||||||||||||||||
4th Quarter
|
$
|
3.41
|
$
|
0.28
|
$
|
0.88
|
$
|
1.64
|
$
|
1.82
|
$
|
2.15
|
$
|
0.56
|
$
|
0.48
|
$
|
88.18
|
||||||||||||||||||
2012 Averages
|
$
|
2.79
|
$
|
0.40
|
$
|
1.00
|
$
|
1.65
|
$
|
1.81
|
$
|
2.15
|
$
|
0.60
|
$
|
0.49
|
$
|
94.20
|
||||||||||||||||||
(1) Natural gas prices are based on Henry-Hub I-FERC commercial index prices.
(2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service.
(3) Polymer-grade propylene prices represent average contract pricing for such product as reported by Chemical Market Associates, Inc. ("CMAI"). Refinery grade propylene prices represent weighted-average spot prices for such product as reported by CMAI.
(4) Crude oil prices are based on commercial index prices for West Texas Intermediate as measured on the New York Mercantile Exchange ("NYMEX").
|
§
|
The weighted-average indicative market price for NGLs (based on prices for such products at Mont Belvieu, Texas, which is the primary industry hub for domestic NGL production) was $1.12 per gallon during 2012 versus $1.46 per gallon during 2011 – a 23% year-to-year decrease.
|
§
|
The market price of natural gas (as measured at the Henry Hub in Louisiana) averaged $2.79 per MMBtu during 2012 versus $4.04 per MMBtu during 2011 – a 31% year-to-year decrease.
|
§
|
The market price of crude oil (as measured on the NYMEX) averaged $94.20 per barrel during 2012 compared to $95.12 per barrel during 2011 – a 1% year-to-year decrease.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Segment gross operating margin:
|
||||||||||||
Natural gas processing and related NGL
marketing activities
|
$
|
1,443.0
|
$
|
1,324.4
|
$
|
989.9
|
||||||
NGL pipelines and related storage
|
740.7
|
638.4
|
604.8
|
|||||||||
NGL fractionation
|
284.8
|
221.4
|
137.9
|
|||||||||
Total
|
$
|
2,468.5
|
$
|
2,184.2
|
$
|
1,732.6
|
||||||
Selected volumetric data:
|
||||||||||||
NGL transportation volumes (MBPD)
|
2,472
|
2,284
|
2,322
|
|||||||||
NGL fractionation volumes (MBPD)
|
659
|
575
|
485
|
|||||||||
Equity NGL production (MBPD) (1)
|
101
|
116
|
121
|
|||||||||
Fee-based natural gas processing (MMcf/d) (2)
|
4,382
|
3,820
|
2,932
|
|||||||||
|
||||||||||||
(1) Represents the NGL volumes we earn and take title to in connection with our processing activities. In general, equity NGL production decreased in 2012 compared to 2011 and 2010 due to reduced ethane recoveries associated with the weakness in natural gas processing margins resulting from lower NGL prices.
(2) Volumes reported correspond to the revenue streams earned by our gas plants. The increase in fee-based processing volumes in 2012 is primarily due to (i) the start-up of our Yoakum gas plant in May 2012 and (ii) changes in processing agreements whereby producers are electing to process more of their natural gas on a fee basis in order to retain NGLs extracted from their natural gas streams, which, in turn, also lowers our equity NGL production.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Segment gross operating margin
|
$
|
775.5
|
$
|
675.3
|
$
|
527.2
|
||||||
Selected volumetric data:
|
||||||||||||
Natural gas transportation volumes (BBtus/d)
|
13,634
|
13,231
|
11,482
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Segment gross operating margin
|
$
|
387.7
|
$
|
234.0
|
$
|
113.7
|
||||||
Selected volumetric data:
|
||||||||||||
Crude oil transportation volumes (MBPD)
|
828
|
678
|
670
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Segment gross operating margin
|
$
|
173.0
|
$
|
228.2
|
$
|
297.8
|
||||||
Selected volumetric data: (1)
|
||||||||||||
Natural gas transportation volumes (BBtus/d)
|
853
|
1,065
|
1,242
|
|||||||||
Crude oil transportation volumes (MBPD)
|
300
|
279
|
320
|
|||||||||
Platform natural gas processing (MMcf/d)
|
291
|
405
|
513
|
|||||||||
Platform crude oil processing (MBPD)
|
17
|
17
|
17
|
|||||||||
|
||||||||||||
(1) The Offshore Pipelines & Services segment continues to be adversely impacted by lower volumes attributable to the federal offshore drilling moratorium in 2010. In recent months, however, the rig count and drilling activity in the Gulf of Mexico has reached pre-moratorium levels.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Segment gross operating margin:
|
||||||||||||
Propylene fractionation and related activities
|
$
|
193.1
|
$
|
161.2
|
$
|
212.4
|
||||||
Butane isomerization
|
95.8
|
124.9
|
84.9
|
|||||||||
Octane enhancement and related plant operations
|
100.9
|
109.1
|
47.0
|
|||||||||
Refined products pipelines and related activities
|
89.9
|
79.6
|
170.8
|
|||||||||
Marine transportation and other
|
100.2
|
60.4
|
69.4
|
|||||||||
Total
|
$
|
579.9
|
$
|
535.2
|
$
|
584.5
|
||||||
Selected volumetric data:
|
||||||||||||
Propylene fractionation volumes (MBPD)
|
72
|
73
|
77
|
|||||||||
Butane isomerization volumes (MBPD)
|
95
|
101
|
89
|
|||||||||
Octane additive and related plant
production volumes (MBPD)
|
16
|
17
|
16
|
|||||||||
Transportation volumes, primarily refined
products and petrochemicals (MBPD)
|
689
|
783
|
893
|
|
Scheduled Maturities of Debt
|
|||||||||||||||||||||||||||
|
Total
|
2013
|
2014
|
2015
|
2016
|
2017
|
After
2017
|
|||||||||||||||||||||
Commercial Paper Notes
|
$
|
346.6
|
$
|
346.6
|
$
|
--
|
$
|
--
|
$
|
--
|
$
|
--
|
$
|
--
|
||||||||||||||
Senior Notes
|
14,300.0
|
1,200.0
|
1,150.0
|
1,300.0
|
750.0
|
800.0
|
9,100.0
|
|||||||||||||||||||||
Junior Subordinated Notes
|
1,532.7
|
--
|
--
|
--
|
--
|
--
|
1,532.7
|
|||||||||||||||||||||
Total
|
$
|
16,179.3
|
$
|
1,546.6
|
$
|
1,150.0
|
$
|
1,300.0
|
$
|
750.0
|
$
|
800.0
|
$
|
10,632.7
|
|
Number of
Common
Units Issued
|
Net
Proceeds
Received
|
||||||
Year Ended December 31, 2010: (1)
|
||||||||
Common units issued in connection with underwritten offerings
|
37,950,000
|
$
|
1,346.7
|
|||||
Common units issued in connection with the DRIP and EUPP
|
8,378,053
|
273.8
|
||||||
Total
|
46,328,053
|
$
|
1,620.5
|
|||||
|
||||||||
Year Ended December 31, 2011:
|
||||||||
Common units issued in connection with underwritten offerings
|
10,350,000
|
$
|
448.5
|
|||||
Common units issued in connection with the DRIP and EUPP
|
2,337,904
|
94.4
|
||||||
Total
|
12,687,904
|
$
|
542.9
|
|||||
|
||||||||
Year Ended December 31, 2012:
|
||||||||
Common units issued in connection with underwritten offerings
|
9,200,000
|
$
|
473.3
|
|||||
Common units issued in connection with the at-the-market program (2)
|
3,978,545
|
203.8
|
||||||
Common units issued in connection with the DRIP and EUPP
|
2,814,660
|
139.7
|
||||||
Total
|
15,993,205
|
$
|
816.8
|
|||||
|
||||||||
(1) Of the 46,328,053 common units issued during 2010, 33,103,053 were issued prior to the Holdings Merger. As a result, net cash proceeds from these pre-Holdings Merger common unit issuances are a component of cash contributions from noncontrolling interests as presented on our Statements of Cash Flows. Net cash proceeds from these pre-Holdings Merger issuances were approximately $1.1 billion. See Note 1 of the Notes to Consolidated Financial Statements for information regarding the basis of presentation of our consolidated financial statements for 2010 in connection with the Holdings Merger.
(2) The sale of common units under the at-the-market program was initiated during the third quarter of 2012.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Net cash flows provided by operating activities
|
$
|
2,890.9
|
$
|
3,330.5
|
$
|
2,300.0
|
||||||
Cash used in investing activities
|
3,018.8
|
2,777.6
|
3,251.6
|
|||||||||
Cash provided by (used in) financing activities
|
124.2
|
(598.6
|
)
|
961.1
|
§
|
Net borrowings under our consolidated debt agreements increased $738.4 million year-to-year. EPO issued $2.5 billion and repaid $1.0 billion in principal amount of senior notes during 2012, compared to the issuance of $2.75 billion and repayment of $450.0 million in principal amount of senior notes during 2011. In addition, net repayments under our consolidated revolving bank credit facilities and term loans decreased $1.14 billion year-to-year. For additional information regarding our consolidated debt obligations, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
|
§
|
Cash outflows related to the monetization of interest rate derivative instruments increased $124.6 million year-to-year. During 2012, we settled a number of forward starting swaps and fixed-to-floating interest rate swaps resulting in a combined net cash outflow of $147.8 million in connection with the issuance of senior notes. Likewise in 2011, we settled a number of forward starting swaps and treasury locks resulting in a net cash outflow of $23.2 million in connection with the issuance of senior notes. For information regarding our interest rate hedging activities, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
|
§
|
Cash distributions paid to limited partners increased $204.3 million year-to-year primarily due to a higher number of distribution-bearing common units outstanding and the associated quarterly distribution rates.
|
§
|
Net cash proceeds from the issuance of common units increased $273.9 million year-to-year. In total, we issued an aggregate 15,993,205 common units during 2012 in connection with underwritten offerings and our DRIP, EUPP and at-the-market program. This compares to 12,687,904 common units we issued during 2011 in connection with underwritten offerings and our DRIP and EUPP. For additional information regarding our consolidated partners equity amounts, see Note 13 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
|
§
|
Cash used for business combinations decreased $1.31 billion year-to-year, primarily due to the acquisition of the State Line and Fairplay natural gas gathering systems for approximately $1.2 billion in May 2010.
|
§
|
Proceeds from the disposal of assets increased $947.9 million year-to-year primarily due to the sale of a portion of our investment in Energy Transfer Equity for $375.2 million and the sale of certain natural gas storage facilities for $547.8 million during 2011.
|
§
|
Capital spending for property, plant and equipment, net of contributions in aid of construction costs, increased $1.84 billion year-to-year primarily due to our Eagle Ford Shale and Haynesville Shale growth capital projects.
|
§
|
Net borrowings under our consolidated debt agreements decreased $191.7 million year-to-year. EPO issued $2.75 billion of new senior notes and repaid $450.0 million in senior notes during 2011 compared to the issuance of $2.0 billion in senior notes and repayment of $500.0 million in senior notes and $54.0 million of other long-term debt during 2010. In addition, net repayments under consolidated revolving credit facilities and term loans increased approximately $988.3 million year-to-year.
|
§
|
Cash distributions to partners and noncontrolling interests were a combined $2.04 billion during 2011 compared to $1.78 billion during 2010. The increase in cash distributions is primarily due to increases in the number of Enterprise's distribution-bearing common units outstanding (including common units issued in connection with the Holdings Merger and Duncan Merger) and in its quarterly distribution rates.
|
§
|
On a combined basis, cash contributions from noncontrolling interests and net cash proceeds from the issuance of common units decreased $1.07 billion year-to-year. Substantially all of the cash contributions from noncontrolling interests during 2010 relate to net cash proceeds generated from the issuance of common units by Enterprise prior to the completion of the Holdings Merger. In total, Enterprise issued 12,687,904 common units and 46,328,053 common units during 2011 and 2010, respectively, in connection with underwritten offerings and its DRIP and EUPP.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Capital spending for property, plant and equipment, net: (1)
|
||||||||||||
Growth capital projects (2)
|
$
|
3,232.7
|
$
|
3,552.3
|
$
|
1,766.2
|
||||||
Sustaining capital projects (3)
|
365.8
|
290.3
|
235.9
|
|||||||||
Capital spending for business combinations
|
--
|
--
|
1,313.9
|
|||||||||
Investments in unconsolidated affiliates
|
609.5
|
30.0
|
8.0
|
|||||||||
Other investing activities
|
43.1
|
22.4
|
--
|
|||||||||
Total capital spending
|
$
|
4,251.1
|
$
|
3,895.0
|
$
|
3,324.0
|
||||||
|
||||||||||||
(1) On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. Contributions in aid of construction costs were $23.4 million, $24.9 million and $38.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. Growth and sustaining capital amounts presented in the table are presented net of related contributions in aid of construction costs.
(2) Growth capital projects either result in additional revenue streams from existing assets or expand our asset base through construction of new facilities that will generate additional revenue streams.
(3) Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to and major renewals of existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Expensed
|
$
|
67.2
|
$
|
64.7
|
$
|
39.4
|
||||||
Capitalized
|
79.4
|
52.6
|
40.4
|
|||||||||
Total
|
$
|
146.6
|
$
|
117.3
|
$
|
79.8
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
NGL Pipelines & Services
|
$
|
2,468.5
|
$
|
2,184.2
|
$
|
1,732.6
|
||||||
Onshore Natural Gas Pipelines & Services
|
775.5
|
675.3
|
527.2
|
|||||||||
Onshore Crude Oil Pipelines & Services
|
387.7
|
234.0
|
113.7
|
|||||||||
Offshore Pipeline & Services
|
173.0
|
228.2
|
297.8
|
|||||||||
Petrochemical & Refined Products Services
|
579.9
|
535.2
|
584.5
|
|||||||||
Other Investments (1)
|
2.4
|
14.8
|
(2.8
|
)
|
||||||||
Total segment gross operating margin
|
$
|
4,387.0
|
$
|
3,871.7
|
$
|
3,253.0
|
||||||
|
||||||||||||
(1) Represents the equity earnings we recorded from our previously held investment in Energy Transfer Equity. Our reporting for this segment ceased on January 18, 2012 when we stopped using the equity method to account for this investment. See Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding the liquidation of our investment in Energy Transfer Equity.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Total segment gross operating margin
|
$
|
4,387.0
|
$
|
3,871.7
|
$
|
3,253.0
|
||||||
Adjustments to reconcile total segment gross operating margin to operating income:
|
||||||||||||
Amounts included in operating costs and expenses:
|
||||||||||||
Depreciation, amortization and accretion
|
(1,061.7
|
)
|
(958.7
|
)
|
(936.3
|
)
|
||||||
Non-cash asset impairment charges
|
(63.4
|
)
|
(27.8
|
)
|
(8.4
|
)
|
||||||
Operating lease expenses paid by EPCO
|
--
|
(0.3
|
)
|
(0.7
|
)
|
|||||||
Gains attributable to disposal of assets
|
17.6
|
156.0
|
44.4
|
|||||||||
General and administrative costs
|
(170.3
|
)
|
(181.8
|
)
|
(204.8
|
)
|
||||||
Operating income
|
3,109.2
|
2,859.1
|
2,147.2
|
|||||||||
Other expense, net
|
(698.4
|
)
|
(743.6
|
)
|
(737.4
|
)
|
||||||
Income before income taxes
|
$
|
2,410.8
|
$
|
2,115.5
|
$
|
1,409.8
|
|
Payment or Settlement due by Period
|
|||||||||||||||||||
|
Less than
|
1-3 | 4-5 |
More than
|
||||||||||||||||
Contractual Obligations
|
Total
|
1 year
|
years
|
years
|
5 years
|
|||||||||||||||
Scheduled maturities of debt obligations (1)
|
$
|
16,179.3
|
$
|
1,546.6
|
$
|
2,450.0
|
$
|
1,550.0
|
$
|
10,632.7
|
||||||||||
Estimated cash payments for interest (2)
|
$
|
17,072.7
|
$
|
840.4
|
$
|
1,471.4
|
$
|
1,350.4
|
$
|
13,410.5
|
||||||||||
Operating lease obligations (3)
|
$
|
363.0
|
$
|
51.3
|
$
|
86.9
|
$
|
70.8
|
$
|
154.0
|
||||||||||
Purchase obligations: (4)
|
||||||||||||||||||||
Product purchase commitments:
|
||||||||||||||||||||
Estimated payment obligations:
|
||||||||||||||||||||
Natural gas
|
$
|
4,027.2
|
$
|
911.8
|
$
|
1,400.6
|
$
|
952.9
|
$
|
761.9
|
||||||||||
NGLs
|
$
|
1,704.8
|
$
|
1,136.3
|
$
|
568.5
|
$
|
--
|
$
|
--
|
||||||||||
Crude oil
|
$
|
386.1
|
$
|
386.1
|
$
|
--
|
$
|
--
|
$
|
--
|
||||||||||
Petrochemicals and refined products
|
$
|
2,121.8
|
$
|
1,519.7
|
$
|
485.1
|
$
|
117.0
|
$
|
--
|
||||||||||
Other
|
$
|
127.7
|
$
|
83.9
|
$
|
14.8
|
$
|
13.2
|
$
|
15.8
|
||||||||||
Underlying major volume commitments:
|
||||||||||||||||||||
Natural gas (in TBtus)
|
1,442
|
321
|
497
|
348
|
276
|
|||||||||||||||
NGLs (in MMBbls)
|
44
|
27
|
17
|
--
|
--
|
|||||||||||||||
Crude oil (in MMBbls)
|
5
|
5
|
--
|
--
|
--
|
|||||||||||||||
Petrochemicals and refined products
(in MMBbls)
|
29
|
20
|
7
|
2
|
--
|
|||||||||||||||
Service payment commitments (5)
|
$
|
745.5
|
$
|
114.5
|
$
|
195.9
|
$
|
178.0
|
$
|
257.1
|
||||||||||
Capital expenditure commitments (6)
|
$
|
1,754.0
|
$
|
1,754.0
|
$
|
--
|
$
|
--
|
$
|
--
|
||||||||||
Other long-term liabilities (7)
|
$
|
205.0
|
$
|
--
|
$
|
39.3
|
$
|
13.2
|
$
|
152.5
|
||||||||||
Total
|
$
|
44,687.1
|
$
|
8,344.6
|
$
|
6,712.5
|
$
|
4,245.5
|
$
|
25,384.5
|
||||||||||
|
||||||||||||||||||||
(1) Represents contractually scheduled future maturities of our consolidated debt principal obligations. For information regarding our consolidated debt obligations, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
(2) Estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2012, the scheduled maturities of such balances, and the applicable fixed or variable interest rates paid during 2012. With respect to our variable-rate debt obligations, we applied the weighted-average interest rate paid during 2012 to determine the estimated cash payments. See Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for the weighted-average variable interest rate charged in 2012 under our revolving credit facility. In addition, our estimate of cash payments for interest gives effect to interest rate swap agreements that were in place at December 31, 2012. See Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding these derivative instruments. Our estimated cash payments for interest are significantly influenced by the long-term maturities of our junior subordinated notes (due August 2066 through January 2068). Our estimated cash payments for interest with respect to each junior subordinated note are based on the current fixed interest rate for each note applied to the entire remaining term through the respective maturity date.
(3) Primarily represents leases of underground salt dome caverns for the storage of natural gas and NGLs, office space with affiliates of EPCO and land held pursuant to right-of-way agreements.
(4) Represents enforceable and legally binding agreements to purchase goods or services as of December 31, 2012. The estimated payment obligations are based on contractual prices in effect at December 31, 2012 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery.
(5) Primarily represents our unconditional payment obligations under firm pipeline transportation contracts.
(6) Represents unconditional payment obligations for services to be rendered or products to be delivered in connection with our capital spending program, including our share of the capital spending of our unconsolidated affiliates.
(7) As reflected on our consolidated balance sheet at December 31, 2012, other long-term liabilities primarily represent the noncurrent portion of asset retirement obligations, deferred revenues and accrued obligations for pipeline transportation deficiency fees and interest rate derivative instruments.
|
§
|
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.
|
Hedged Transaction
|
Number and Type of
Derivatives Outstanding
|
Notional
Amount
|
Period of
Hedge
|
Rate
Swap
|
Accounting
Treatment
|
|||
Senior Notes AA
|
10 fixed-to-floating swaps
|
$
|
750.0
|
1/2011 to 2/2016
|
3.2% to 1.3%
|
Fair value hedge
|
||
Undesignated swaps
|
6 floating-to-fixed swaps
|
$
|
600.0
|
5/2010 to 7/2014
|
0.4% to 2.0%
|
Mark-to-market
|
Interest Rate Swap Portfolio
Aggregate Fair Value at
|
|||||||||||||
Resulting
Classification
|
December 31,
|
December 31,
|
January 31,
|
||||||||||
Scenario
|
2011
|
2012
|
2013
|
||||||||||
FV assuming no change in underlying interest rates
|
Asset
|
$
|
67.2
|
$
|
28.0
|
$
|
29.1
|
||||||
FV assuming 10% increase in underlying interest rates
|
Asset
|
64.4
|
27.2
|
28.1
|
|||||||||
FV assuming 10% decrease in underlying interest rates
|
Asset
|
70.0
|
28.8
|
30.0
|
Hedged Transaction
|
Number and Type of
Derivatives Outstanding
|
Notional
Amount
|
Expected
Termination
Date
|
Average Rate
Locked
|
Accounting
Treatment
|
|||||||||
Future debt offering
|
16 forward starting swaps
|
$
|
1,000.0
|
3/2013
|
3.7
|
%
|
Cash flow hedge
|
Forward Starting Swap Portfolio
Aggregate Fair Value at
|
|||||||||||||
Resulting
Classification
|
December 31,
|
December 31,
|
January 31,
|
||||||||||
Scenario
|
2011
|
2012
|
2013
|
||||||||||
FV assuming no change in underlying interest rates
|
Liability
|
$
|
(290.7
|
)
|
$
|
(175.4
|
)
|
$
|
(153.9
|
)
|
|||
FV assuming 10% increase in underlying interest rates
|
Liability
|
(251.8
|
)
|
(157.5
|
)
|
(134.2
|
)
|
||||||
FV assuming 10% decrease in underlying interest rates
|
Liability
|
(330.6
|
)
|
(193.7
|
)
|
(173.9
|
)
|
|
Volume (1)
|
Accounting
|
|
Derivative Purpose
|
Current (2)
|
Long-Term (2)
|
Treatment
|
Derivatives designated as hedging instruments:
|
|
|
|
Octane enhancement:
|
|
|
|
Forecasted purchases of NGLs (MMBbls)
|
1.3
|
n/a
|
Cash flow hedge
|
Forecasted sales of octane enhancement products (MMBbls)
|
2.8
|
0.1
|
Cash flow hedge
|
Natural gas marketing:
|
|
|
|
Forecasted sales of natural gas (Bcf)
|
3.2
|
n/a
|
Cash flow hedge
|
Natural gas storage inventory management activities (Bcf)
|
16.2
|
n/a
|
Fair value hedge
|
NGL marketing:
|
|
|
|
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)
|
2.6
|
n/a
|
Cash flow hedge
|
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)
|
5.5
|
n/a
|
Cash flow hedge
|
Refined products marketing:
|
|
|
|
Forecasted purchases of refined products (MMBbls)
|
0.8
|
n/a
|
Cash flow hedge
|
Forecasted sales of refined products (MMBbls)
|
1.3
|
n/a
|
Cash flow hedge
|
Refined products inventory management activities (MMBbls)
|
0.1
|
n/a
|
Fair value hedge
|
Crude oil marketing:
|
|
|
|
Forecasted purchases of crude oil (MMBbls)
|
3.1
|
n/a
|
Cash flow hedge
|
Forecasted sales of crude oil (MMBbls)
|
6.2
|
n/a
|
Cash flow hedge
|
Derivatives not designated as hedging instruments:
|
|
|
|
Natural gas risk management activities (Bcf) (3,4)
|
138.6
|
24.7
|
Mark-to-market
|
Refined products risk management activities (MMBbls) (4)
|
0.8
|
n/a
|
Mark-to-market
|
Crude oil risk management activities (MMBbls) (4)
|
3.9
|
n/a
|
Mark-to-market
|
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is January 2014, October 2013 and October 2015, respectively.
(3) Current volumes include 39.3 Bcf of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences.
(4) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.
|
§
|
The objective of our NGL, refined products and crude oil sales hedging program is to hedge the margins of anticipated future sales of inventory by locking in sales prices through the use of forward physical sales contracts and commodity derivative instruments.
|
§
|
The objective of our natural gas and refined products inventory hedging program is to hedge the fair value of natural gas and refined products currently held in inventory by locking in the sales price of the inventory through the use of commodity derivative instruments.
|
§
|
The objective of our natural gas processing strategy is to hedge an amount of gross margin associated with our natural gas processing activities. No such hedges were in place as of February 1, 2013. Management continues to evaluate market conditions to determine the appropriate timing, if at all, of implementing this strategy during 2013. When in use, this strategy uses physical and financial instruments to lock in the purchase prices of natural gas consumed as plant thermal reduction ("PTR") and the sales prices of the related NGL products. This program would consist of (i) the forward sale of a portion of our expected
|
|
equity NGL production at fixed prices for a selected period of time (e.g. through December 31, 2013), which would be achieved through the use of forward physical sales contracts and commodity derivative instruments and (ii) the purchase of commodity derivative instruments having a notional amount based on the volume of natural gas expected to be consumed as PTR in the production of such equity NGL production.
|
Portfolio Fair Value at
|
|||||||||||||
Resulting
Classification
|
December 31,
|
December 31,
|
January 31,
|
||||||||||
Scenario
|
2011
|
2012
|
2013
|
||||||||||
FV assuming no change in underlying commodity prices
|
Asset
|
$
|
22.2
|
$
|
7.6
|
$
|
2.3
|
||||||
FV assuming 10% increase in underlying commodity prices
|
Asset (Liability)
|
14.9
|
3.0
|
(1.3
|
)
|
||||||||
FV assuming 10% decrease in underlying commodity prices
|
Asset
|
29.5
|
12.2
|
5.9
|
Portfolio Fair Value at
|
|||||||||||||
Resulting
Classification
|
December 31,
|
December 31,
|
January 31,
|
||||||||||
Scenario
|
2011
|
2012
|
2013
|
||||||||||
FV assuming no change in underlying commodity prices
|
Asset (Liability)
|
$
|
(12.3
|
)
|
$
|
10.5
|
$
|
(16.8
|
)
|
||||
FV assuming 10% increase in underlying commodity prices
|
Liability
|
(32.2
|
)
|
(27.5
|
)
|
(60.4
|
)
|
||||||
FV assuming 10% decrease in underlying commodity prices
|
Asset
|
7.6
|
48.5
|
26.8
|
Portfolio Fair Value at
|
|||||||||||||
Resulting
Classification
|
December 31,
|
December 31,
|
January 31,
|
||||||||||
Scenario
|
2011
|
2012
|
2013
|
||||||||||
FV assuming no change in underlying commodity prices
|
Liability
|
$
|
(7.6
|
)
|
$
|
(2.0
|
)
|
$
|
(3.7
|
)
|
|||
FV assuming 10% increase in underlying commodity prices
|
Liability
|
(10.0
|
)
|
(10.0
|
)
|
(16.1
|
)
|
||||||
FV assuming 10% decrease in underlying commodity prices
|
Asset (Liability)
|
(5.0
|
)
|
6.1
|
8.7
|
(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/ Michael A. Creel
|
|
/s/ W. Randall Fowler
|
||
Name:
|
Michael A. Creel
|
|
Name:
|
W. Randall Fowler
|
Title:
|
Chief Executive Officer of our general
|
|
Title:
|
Chief Financial Officer of our general
|
|
partner, Enterprise Products Holdings LLC
|
|
|
partner, Enterprise Products Holdings LLC
|
Name
|
Age
|
Position with Enterprise GP
|
Randa Duncan Williams
|
51
|
Director and Chairman of the Board
|
Thurmon M. Andress (1)
|
79
|
Director
|
Richard H. Bachmann
|
60
|
Director
|
E. William Barnett (1,2)
|
80
|
Director
|
Larry J. Casey (1)
|
80
|
Director
|
Michael A. Creel (3)
|
59
|
Director and CEO
|
Dr. Ralph S. Cunningham
|
72
|
Director
|
W. Randall Fowler (3)
|
56
|
Director, Executive Vice President and CFO
|
Charles E. McMahen (4,5)
|
73
|
Director
|
Rex C. Ross (4)
|
69
|
Director
|
Edwin E. Smith (1)
|
81
|
Director
|
Richard S. Snell (4)
|
70
|
Director
|
A. James Teague (3)
|
67
|
Director and COO
|
Lynn L. Bourdon, III (3)
|
51
|
Group Senior Vice President
|
Terrance L. Hurlburt (3)
|
60
|
Group Senior Vice President
|
William Ordemann (3)
|
53
|
Group Senior Vice President
|
Thomas M. Zulim (3)
|
55
|
Group Senior Vice President
|
Bryan F. Bulawa (3)
|
43
|
Senior Vice President and Treasurer
|
Stephanie C. Hildebrandt (3)
|
48
|
Senior Vice President, General Counsel and Secretary
|
Michael J. Knesek (3)
|
58
|
Senior Vice President, Controller and Principal Accounting Officer
|
|
|
|
(1) Member of the Governance Committee
(2) Chairman of the Governance Committee
(3) Executive officer
(4) Member of the Audit Committee
(5) Chairman of the Audit Committee
|
|
|
Cash
|
Cash
|
Unit
|
Option
|
All Other
|
|||||||||||||||||||
Name and
|
|
Salary
|
Bonus
|
Awards
|
Awards
|
Comp.
|
Total
|
||||||||||||||||||
Principal Position
|
Year
|
($)
|
($) (1)
|
($) (2)
|
($) (3)
|
($) (4)
|
($)
|
||||||||||||||||||
Michael A. Creel
|
2012
|
$
|
769,000
|
$
|
1,550,000
|
$
|
3,738,240
|
$
|
--
|
$
|
597,606
|
$
|
6,654,846
|
||||||||||||
(CEO)
|
2011
|
707,275
|
1,425,000
|
2,640,354
|
--
|
530,461
|
5,303,090
|
||||||||||||||||||
2010
|
607,187
|
1,046,875
|
2,091,096
|
208,905
|
388,681
|
4,342,744
|
|||||||||||||||||||
|
|
||||||||||||||||||||||||
W. Randall Fowler
|
2012
|
415,097
|
562,500
|
1,947,000
|
--
|
312,216
|
3,236,813
|
||||||||||||||||||
(Executive Vice President and CFO)
|
2011
|
402,905
|
562,500
|
1,442,100
|
--
|
287,595
|
2,695,100
|
||||||||||||||||||
2010
|
275,625
|
262,500
|
822,885
|
87,044
|
166,070
|
1,614,124
|
|||||||||||||||||||
|
|
||||||||||||||||||||||||
A. James Teague
|
2012
|
685,150
|
1,550,000
|
3,364,416
|
--
|
459,763
|
6,059,329
|
||||||||||||||||||
(COO)
|
2011
|
665,113
|
1,300,000
|
1,922,800
|
--
|
412,067
|
4,299,980
|
||||||||||||||||||
2010
|
650,000
|
650,000
|
1,710,310
|
174,087
|
372,446
|
3,556,843
|
|||||||||||||||||||
|
|
||||||||||||||||||||||||
Lynn L. Bourdon, III
|
2012
|
397,500
|
430,000
|
1,298,000
|
--
|
185,433
|
2,310,933
|
||||||||||||||||||
(Group Senior Vice President)
|
2011
|
387,656
|
400,000
|
961,400
|
--
|
171,128
|
1,920,184
|
||||||||||||||||||
2010
|
379,219
|
300,000
|
451,780
|
87,044
|
190,440
|
1,408,483
|
|||||||||||||||||||
|
|
||||||||||||||||||||||||
William Ordemann
|
2012
|
422,900
|
300,000
|
1,038,400
|
--
|
294,486
|
2,055,786
|
||||||||||||||||||
(Group Senior Vice President)
|
2011
|
414,612
|
250,000
|
1,311,000
|
--
|
329,170
|
2,304,782
|
||||||||||||||||||
2010
|
406,300
|
250,000
|
1,090,726
|
174,087
|
283,173
|
2,204,286
|
|||||||||||||||||||
|
|
||||||||||||||||||||||||
(1) Amounts represent discretionary annual cash awards accrued with respect to the years presented. Cash awards are paid in February of the following year (e.g., the cash awards with respect to 2012 were paid in February 2013).
(2) Amounts represent our estimated share of the aggregate grant date fair value of restricted common unit awards granted during each year presented. For information about assumptions made in the valuation of these awards and limited partner interests, see Note 5 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report, the applicable disclosures of which are incorporated by reference into this Item 11.
(3) Amounts represent our estimated share of the aggregate grant date fair value of unit option awards granted during each year presented. For information about assumptions made in the valuation of these awards, see Note 5 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report, the applicable disclosures of which are incorporated by reference into this Item 11.
(4) Amounts include (i) contributions in connection with funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid on incentive plan awards, (iii) the imputed value of life insurance premiums paid on behalf of the officer and (iv) other amounts. See the following table for additional information.
|
|
Contributions
Under Funded,
Qualified,
Defined
Contribution
Retirement
Plans
|
Quarterly
Distributions
Paid On
Incentive
Plan Awards
|
Life
Insurance
Premiums
|
Other
|
Total
All Other
Compensation
|
|||||||||||||||
Michael A. Creel
|
$
|
27,500
|
$
|
561,524
|
$
|
2,322
|
$
|
6,260
|
$
|
597,606
|
||||||||||
W. Randall Fowler
|
20,625
|
284,746
|
1,741
|
5,104
|
312,216
|
|||||||||||||||
A. James Teague
|
27,500
|
419,419
|
6,858
|
5,986
|
459,763
|
|||||||||||||||
William Ordemann
|
30,000
|
258,949
|
1,242
|
4,295
|
294,486
|
|||||||||||||||
Lynn L. Bourdon, III
|
25,000
|
155,291
|
1,242
|
3,900
|
185,433
|
|
|
Enterprise
|
EPCO and
|
Total
|
|
|
Products
|
other
|
Time
|
Named Executive Officer
|
Year
|
Partners
|
affiliates
|
Allocated
|
Michael A. Creel (CEO)
|
2012
|
100%
|
--
|
100%
|
|
2011
|
95%
|
5%
|
100%
|
|
2010
|
84%
|
16%
|
100%
|
|
|
|
|
|
W. Randall Fowler (CFO)
|
2012
|
75%
|
25%
|
100%
|
|
2011
|
75%
|
25%
|
100%
|
|
2010
|
53%
|
47%
|
100%
|
|
|
|
|
|
A. James Teague
|
2012
|
100%
|
--
|
100%
|
|
2011
|
100%
|
--
|
100%
|
|
2010
|
100%
|
--
|
100%
|
|
|
|
|
|
William Ordemann
|
2012
|
100%
|
--
|
100%
|
|
2011
|
100%
|
--
|
100%
|
|
2010
|
100%
|
--
|
100%
|
|
|
|
|
|
Lynn L. Bourdon, III
|
2012
|
100%
|
--
|
100%
|
|
2011
|
100%
|
--
|
100%
|
|
2010
|
100%
|
--
|
100%
|
Grant
|
|||||||||||||||||||||
Exercise
|
Date Fair
|
||||||||||||||||||||
or Base
|
Value of
|
||||||||||||||||||||
Estimated Future Payouts Under
|
Price of
|
Unit and
|
|||||||||||||||||||
Equity Incentive Plan Awards
|
Option
|
Option
|
|||||||||||||||||||
Grant
Date
|
Threshold
|
Target
|
Maximum
|
Awards
|
Awards
|
||||||||||||||||
Name
|
(#) |
|
(#) |
|
(#) |
|
($/Unit)
|
($) (1)
|
|||||||||||||
Restricted common unit awards:
|
|
||||||||||||||||||||
Michael A. Creel (CEO)
|
2/21/12
|
--
|
72,000
|
--
|
--
|
$
|
3,738,240
|
||||||||||||||
W. Randall Fowler (CFO)
|
2/21/12
|
--
|
50,000
|
--
|
--
|
1,947,000
|
|||||||||||||||
A. James Teague
|
2/21/12
|
--
|
64,800
|
--
|
--
|
3,364,416
|
|||||||||||||||
William Ordemann
|
2/21/12
|
--
|
20,000
|
--
|
--
|
1,038,400
|
|||||||||||||||
Lynn L. Bourdon, III
|
2/21/12
|
--
|
25,000
|
--
|
--
|
1,298,000
|
|||||||||||||||
|
|
||||||||||||||||||||
(1) Amounts presented reflect that portion of grant date fair value allocable to us based on the average percentage of time each named executive officer spent on our consolidated businesses during 2012. Based on current allocations, we estimate that the consolidated compensation expense we record for each named executive officer with respect to these awards will approximate these grant date fair value amounts over the vesting period. The closing price of our common units on February 21, 2012 was $51.92 per unit.
|
Option Awards
|
Unit Awards
|
||||||||||||||||||||||||
Number of
|
Number of
|
Market
|
|||||||||||||||||||||||
Units
|
Units
|
Number
|
Value
|
||||||||||||||||||||||
Underlying
|
Underlying
|
Option
|
of Units
|
of Units
|
|||||||||||||||||||||
Options
|
Options
|
Exercise
|
Option
|
That Have
|
That Have
|
||||||||||||||||||||
Vesting
Date
|
Exercisable
|
Unexercisable
|
Price
|
Expiration
|
Not Vested
|
Not Vested
|
|||||||||||||||||||
Name
|
(#) |
|
(#) |
|
($/Unit)
|
Date
|
(#) (2) |
|
($) (3)
|
||||||||||||||||
Restricted common unit awards:
|
|||||||||||||||||||||||||
Michael A. Creel (CEO)
|
Various (1)
|
--
|
--
|
--
|
--
|
210,800
|
$
|
10,556,864
|
|||||||||||||||||
W. Randall Fowler (CFO)
|
Various (1)
|
--
|
--
|
--
|
--
|
142,500
|
7,136,400
|
||||||||||||||||||
A. James Teague
|
Various (1)
|
--
|
--
|
--
|
--
|
161,700
|
8,097,936
|
||||||||||||||||||
William Ordemann
|
Various (1)
|
--
|
--
|
--
|
--
|
89,400
|
4,477,152
|
||||||||||||||||||
Lynn L. Bourdon, III
|
Various (1)
|
--
|
--
|
--
|
--
|
61,000
|
3,054,880
|
||||||||||||||||||
|
|
||||||||||||||||||||||||
Unit option awards:
|
|
||||||||||||||||||||||||
Michael A. Creel (CEO):
|
|
||||||||||||||||||||||||
May 22, 2008 option grant (4)
|
5/22/12
|
--
|
90,000
|
$
|
30.93
|
12/31/13
|
--
|
--
|
|||||||||||||||||
February 19, 2009 option grant
|
2/19/13
|
--
|
75,000
|
22.06
|
12/31/14
|
--
|
--
|
||||||||||||||||||
May 6, 2009 option grant
|
5/06/13
|
--
|
90,000
|
24.92
|
12/31/14
|
--
|
--
|
||||||||||||||||||
February 23, 2010 option grant
|
2/23/14
|
--
|
90,000
|
32.27
|
12/31/15
|
--
|
--
|
||||||||||||||||||
W. Randall Fowler (CFO):
|
|
||||||||||||||||||||||||
May 22, 2008 option grant (4)
|
5/22/12
|
--
|
60,000
|
30.93
|
12/31/13
|
--
|
--
|
||||||||||||||||||
February 19, 2009 option grant
|
2/19/13
|
--
|
52,500
|
22.06
|
12/31/14
|
--
|
--
|
||||||||||||||||||
May 6, 2009 option grant
|
5/06/13
|
--
|
60,000
|
24.92
|
12/31/14
|
--
|
--
|
||||||||||||||||||
February 23, 2010 option grant
|
2/23/14
|
--
|
60,000
|
32.27
|
12/31/15
|
--
|
--
|
||||||||||||||||||
A. James Teague:
|
|
||||||||||||||||||||||||
May 22, 2008 option grant (4)
|
5/22/12
|
--
|
60,000
|
30.93
|
12/31/13
|
--
|
--
|
||||||||||||||||||
February 19, 2009 option grant
|
2/19/13
|
--
|
60,000
|
22.06
|
12/31/14
|
--
|
--
|
||||||||||||||||||
May 6, 2009 option grant
|
5/06/13
|
--
|
60,000
|
24.92
|
12/31/14
|
--
|
--
|
||||||||||||||||||
February 23, 2010 option grant
|
2/23/14
|
--
|
60,000
|
32.27
|
12/31/15
|
--
|
--
|
||||||||||||||||||
William Ordemann:
|
|
||||||||||||||||||||||||
May 22, 2008 option grant (4)
|
5/22/12
|
--
|
60,000
|
30.93
|
12/31/13
|
--
|
--
|
||||||||||||||||||
February 19, 2009 option grant
|
2/19/13
|
--
|
45,000
|
22.06
|
12/31/14
|
--
|
--
|
||||||||||||||||||
May 6, 2009 option grant
|
5/06/13
|
--
|
60,000
|
24.92
|
12/31/14
|
--
|
--
|
||||||||||||||||||
February 23, 2010 option grant
|
2/23/14
|
--
|
60,000
|
32.27
|
12/31/15
|
--
|
--
|
||||||||||||||||||
Lynn L. Bourdon, III:
|
|
||||||||||||||||||||||||
May 22, 2008 option grant (4)
|
5/22/12
|
--
|
30,000
|
30.93
|
12/31/13
|
--
|
--
|
||||||||||||||||||
February 19, 2009 option grant
|
2/19/13
|
--
|
30,000
|
22.06
|
12/31/14
|
--
|
--
|
||||||||||||||||||
May 6, 2009 option grant
|
5/06/13
|
--
|
30,000
|
24.92
|
12/31/14
|
--
|
--
|
||||||||||||||||||
February 23, 2010 option grant
|
2/23/14
|
--
|
30,000
|
32.27
|
12/31/15
|
--
|
--
|
||||||||||||||||||
(1) Of the 665,400 non-vested restricted common unit awards presented in the table, 331,550 vest in 2013, 167,050 vest in 2014, 108,850 vest in 2015 and 57,950 vest in 2016.
(2) Amounts represent the total number of restricted common unit awards outstanding for each named executive officer.
(3) Amounts derived by multiplying the total number of restricted common unit awards outstanding for each named executive officer by the closing price of our common units at December 31, 2012 (the last trading day of 2012) of $50.08 per unit.
(4) These option grants are exercisable beginning in February 2013.
|
|
Option Awards
|
Unit Awards
|
||||||||||||||
|
Number of
|
Gross
|
Number of
|
Gross
|
||||||||||||
|
Units
|
Value
|
Units
|
Value
|
||||||||||||
|
Acquired on
|
Realized on
|
Acquired on
|
Realized on
|
||||||||||||
|
Exercise
|
Exercise
|
Vesting
|
Vesting
|
||||||||||||
Name
|
(#) |
|
($) (1)
|
(#) |
|
($) (2)
|
||||||||||
Michael A. Creel (CEO):
|
||||||||||||||||
Option awards
|
16,528
|
$
|
1,149,000
|
|||||||||||||
Restricted common unit awards
|
76,150
|
$
|
3,851,838
|
|||||||||||||
W. Randall Fowler (CFO):
|
||||||||||||||||
Option awards
|
12,594
|
861,750
|
||||||||||||||
Restricted common unit awards
|
51,850
|
2,621,468
|
||||||||||||||
A. James Teague:
|
||||||||||||||||
Option awards
|
16,523
|
1,149,000
|
||||||||||||||
Restricted common unit awards
|
52,350
|
2,647,103
|
||||||||||||||
William Ordemann:
|
||||||||||||||||
Option awards
|
8,463
|
585,000
|
||||||||||||||
Restricted common unit awards
|
44,050
|
2,219,707
|
||||||||||||||
Lynn L. Bourdon, III:
|
||||||||||||||||
Option awards
|
8,873
|
632,100
|
||||||||||||||
Restricted common unit awards
|
17,600
|
892,195
|
||||||||||||||
|
||||||||||||||||
(1) Amount determined by multiplying the number of units acquired on exercise of the options by the difference between the closing price of our common units on the date of exercise and the exercise price.
(2) Amount determined for restricted common unit awards by multiplying the number of restricted common unit awards that vested during 2012 by the closing price of our common units on the date of vesting.
|
|
Accelerated
Option Value
|
|||
Michael A. Creel (CEO)
|
$
|
7,692,300
|
||
W. Randall Fowler (CFO)
|
5,198,250
|
|||
A. James Teague
|
5,408,400
|
|||
William Ordemann
|
4,988,100
|
|||
Lynn L. Bourdon, III
|
2,704,200
|
|
Fees Earned
|
|||||||||||||||
|
or Paid
|
Unit
|
All Other
|
|||||||||||||
|
in Cash
|
Awards
|
Compensation
|
Total
|
||||||||||||
Name
|
($)
|
($)
|
($)
|
($)
|
||||||||||||
Thurmon M. Andress
|
$
|
96,000
|
$
|
74,453
|
$
|
--
|
$
|
170,453
|
||||||||
E. William Barnett (1)
|
111,000
|
74,453
|
--
|
185,453
|
||||||||||||
Larry J. Casey
|
96,000
|
74,453
|
--
|
170,453
|
||||||||||||
Charles E. McMahen (2)
|
117,000
|
74,453
|
--
|
191,453
|
||||||||||||
Rex C. Ross
|
102,000
|
74,453
|
--
|
176,453
|
||||||||||||
Edwin E. Smith
|
96,000
|
74,453
|
--
|
170,453
|
||||||||||||
Richard S. Snell
|
102,000
|
74,453
|
--
|
176,453
|
||||||||||||
(1) Mr. Barnett serves as chairman of the Governance Committee.
(2) Mr. McMahen serves as chairman of the Audit Committee.
|
|
|
Amount and
|
|
|
|
Nature of
|
|
Title of
|
Name and Address
|
Beneficial
|
Percent
|
Class
|
of Beneficial Owner
|
Ownership
|
of Class
|
Common units
|
Randa Duncan Williams
|
334,610,450 (1)
|
37.2%
|
|
1100 Louisiana Street, 10th Floor
|
|
|
|
Houston, Texas 77002
|
|
|
|
|
|
|
Class B units
|
Randa Duncan Williams
|
4,520,431
|
100%
|
|
1100 Louisiana Street, 10th Floor
|
|
|
|
Houston, Texas 77002
|
|
|
(1) For a detailed listing of the ownership amounts that comprise Ms. Williams' total beneficial ownership of our common units, see the table presented in the following section, "Security Ownership of Management," within this Item 12.
|
|
Amount and
|
|||||||
|
Nature Of
|
|||||||
|
Beneficial
|
Percent of
|
||||||
Name of Beneficial Owner
|
Ownership
|
Class
|
||||||
Randa Duncan Williams:
|
||||||||
Units controlled by DD LLC Voting Trust
|
||||||||
Through DFI GP Holdings L.P.
|
40,844,206
|
4.5%
|
|
|||||
Through Dan Duncan LLC
|
20,881
|
*
|
||||||
Units controlled by EPCO Voting Trust:
|
||||||||
Through EPCO
|
523,306
|
*
|
||||||
Through EPCO Investments, LLC
|
15,241,517
|
1.7%
|
|
|||||
Through Duncan Family Interests, Inc.
|
257,909,910
|
28.7%
|
|
|||||
Through EPCO Holdings, Inc.
|
7,839,629
|
*
|
||||||
Units controlled by estate of Dan L. Duncan (1)
|
10,111,436
|
1.1%
|
|
|||||
Units controlled by Alkek and Williams, Ltd.
|
163,000
|
*
|
||||||
Units controlled by family trusts (2)
|
1,950,000
|
*
|
||||||
Units owned personally (3)
|
6,565
|
*
|
||||||
Total for Randa Duncan Williams
|
334,610,450
|
37.2%
|
|
|||||
|
||||||||
Michael A. Creel (CEO) (4,5)
|
778,446
|
*
|
||||||
W. Randall Fowler (CFO) (4,6)
|
607,842
|
*
|
||||||
A. James Teague (4,7)
|
876,182
|
*
|
||||||
William Ordemann (4,8)
|
452,587
|
*
|
||||||
Lynn L. Bourdon, III (4,9)
|
305,085
|
*
|
||||||
Thurmon M. Andress (10)
|
36,278
|
*
|
||||||
Richard H. Bachmann (11)
|
662,687
|
*
|
||||||
E. William Barnett
|
21,113
|
*
|
||||||
Larry J. Casey (12)
|
23,613
|
*
|
||||||
Dr. Ralph S. Cunningham (13)
|
511,555
|
*
|
||||||
Charles E. McMahen
|
40,085
|
*
|
||||||
Rex C. Ross (14)
|
64,524
|
*
|
||||||
Edwin E. Smith
|
188,378
|
*
|
||||||
Richard S. Snell
|
11,797
|
*
|
||||||
All current directors and executive officers of Enterprise GP, as
a group (20 individuals in total) (15)
|
340,204,258
|
37.8%
|
|
|||||
|
||||||||
* Represents a beneficial ownership of less than 1% of class
|
||||||||
(1) The number of common units presented for the estate of Dan L. Duncan includes common units held of record by DD Securities LLC.
(2) The number of common units presented for Ms. Williams includes 1,512,500 common units held by family trusts for which she is the trustee but has disclaimed beneficial ownership.
(3) The number of common units presented for Ms. Williams includes 4,545 common units held of record by her spouse and 2,020 common units held of record jointly with her spouse.
(4) These individuals are the named executive officers for 2012.
(5) The number of common units presented for Mr. Creel includes 90,000 common unit options that are exercisable beginning in February 2013.
(6) The number of common units presented for Mr. Fowler includes (i) 250,000 common units held by a family limited partnership (for which he has disclaimed beneficial ownership except to the extent of his pecuniary interest) and (ii) 60,000 common unit options that are exercisable beginning in February 2013.
(7) The number of common units presented for Mr. Teague includes (i) 189,409 common units held by an immediate family member, (ii) 26,500 common units held by a family trust and (iii) 60,000 common unit options that are exercisable beginning in February 2013.
(8) The number of common units presented for Mr. Ordemann includes 60,000 common unit options that are exercisable beginning in February 2013.
(9) The number of common units presented for Mr. Bourdon includes (i) 30,000 common unit options that are exercisable beginning in February 2013 and (ii) 600 common units held by immediate family members.
(10) The number of common units presented for Mr. Andress includes (i) 1,200 common units held by an immediate family member, (ii) 15,532 common units held by a family partnership and (iii) 712 common units held by family trusts.
(11) The number of common units presented for Mr. Bachmann includes (i) 15,738 common units held by family trusts, (ii) 2,231 common units held by an immediate family member and (iii) 60,000 common unit options that are exercisable beginning in February 2013.
(12) The number of common units presented for Mr. Casey includes 26 common units held by an immediate family member.
(13) The number of common units presented for Dr. Cunningham includes (i) 305,506 common units held by a family limited partnership (for which he has disclaimed beneficial ownership except to the extent of his pecuniary interest), (ii) 23 common units held by the general partner of such family limited partnership and (iii) 60,000 common unit options that are exercisable beginning in February 2013.
(14) The number of common units presented for Mr. Ross includes 53,852 common units held by family trusts.
(15) Cumulatively, this group's beneficial ownership amount includes 525,000 common unit options that are exercisable beginning in February 2013.
|
§
|
each non-management director of our general partner 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 our general partner 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:
|
||||||||||||
1998 Plan (1)
|
30,000
|
$
|
20.08
|
852,974
|
||||||||
2006 Plan (2)
|
91,140
|
$
|
22.98
|
n/a
|
|
|||||||
2008 Plan (3)
|
2,640,000
|
$
|
27.65
|
5,167,075
|
||||||||
Equity compensation plans not approved by unitholders:
|
||||||||||||
None
|
--
|
--
|
--
|
|||||||||
Total for equity compensation plans
|
2,761,140
|
$
|
27.41
|
6,020,049
|
||||||||
|
||||||||||||
(1) The 30,000 unit options outstanding at December 31, 2012 are exercisable in 2014.
(2) These awards were granted under the EPCO, Inc. 2006 TPP Long-Term Incentive Plan ("2006 Plan"), which we assumed in connection with the TEPPCO merger. Of the 91,140 unit options outstanding at December 31, 2012, 31,000 are exercisable in 2013 and the remainder are exercisable in 2014. No additional awards are expected to be issued under the 2006 Plan.
(3) Of the 2,640,000 unit options outstanding at December 31, 2012, 645,000 are exercisable in 2013 and 1,300,000 and 695,000 are exercisable in 2014 and 2015, respectively.
|
§
|
pursuant to our Partnership Agreement or the limited liability company agreement of Enterprise GP, as such agreements may be amended from time to time;
|
§
|
in which an officer or director of Enterprise GP or any of our subsidiaries, or an immediate family member of such an officer or director, has a material financial interest or is otherwise a party;
|
§
|
when requested to do so by management or the Board;
|
§
|
with a value of $5 million or more (unless such transaction is equivalent to an arm's length or third party transaction); or
|
§
|
that it may otherwise deem appropriate from time to time.
|
§
|
the 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 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 Year Ended December 31,
|
|||||||
|
2012
|
2011
|
||||||
Audit Fees (1)
|
$
|
3.8
|
$
|
3.8
|
||||
Audit-Related Fees (2)
|
--
|
*
|
||||||
Tax Fees (3)
|
--
|
--
|
||||||
All Other Fees (4)
|
--
|
--
|
||||||
|
||||||||
(1) Audit fees represent amounts billed for each of the years presented for (i) the audit of our annual financial statements and internal controls over financial reporting, (ii) the review of our quarterly financial statements filed on Form 10-Q and (iii) those services normally provided by Deloitte & Touche in connection with our statutory and regulatory filings or engagements, including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this annual report.
(2) Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews and are not reported under the section labeled "Audit Fees." We engaged Deloitte & Touche to perform certain assurance work related to the amendment of an environmental permit in 2011.
(3) Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. No such services were rendered by Deloitte & Touche during the last two years.
(4) All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above.
* Amount is negligible.
|
(a)
|
The following documents are filed as a part of this annual report:
|
(1)
|
Financial Statements: See "Index to Consolidated Financial Statements" beginning on page F-1 of this annual report for the financial statements included herein.
|
(2)
|
Financial Statement Schedules: The separate filing of financial statement schedules has been omitted because such schedules are either not applicable or the information called for therein appears in the footnotes of our Consolidated Financial Statements.
|
(3)
|
Exhibits:
|
Exhibit
Number
|
Exhibit*
|
2.1
|
Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
|
2.2
|
Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
|
2.3
|
Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
|
2.4
|
Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 21, 2004).
|
2.5
|
Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
|
2.6
|
Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub B LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed June 29, 2009).
|
2.7
|
Agreement and Plan of Merger, dated as of June 28, 2009, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Sub A LLC, TEPPCO Partners, L.P. and Texas Eastern Products Pipeline Company, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed June 29, 2009).
|
2.8
|
Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise ETE LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2010).
|
2.9
|
Agreement and Plan of Merger, dated as of September 3, 2010, by and among Enterprise Products GP, LLC, Enterprise GP Holdings L.P. and EPE Holdings, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed September 7, 2010).
|
2.10
|
Contribution Agreement, dated as of September 30, 2010, by and between Enterprise Products Company and Enterprise Products Partners L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K filed October 1, 2010).
|
2.11
|
Agreement and Plan of Merger, dated as of April 28, 2011, by and among Enterprise Products Partners L.P., Enterprise Products Holdings LLC, EPD MergerCo LLC, Duncan Energy Partners L.P. and DEP Holdings, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed April 29, 2011).
|
3.1
|
Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 9, 2007).
|
3.2
|
Certificate of Amendment to Certificate of Limited Partnership of Enterprise Products Partners L.P., filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.6 to Form 8-K filed November 23, 2010).
|
3.3
|
Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated November 22, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K filed November 23, 2010).
|
3.4
|
Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 11, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 16, 2011).
|
3.5
|
Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC) (incorporated by reference to Exhibit 3.3 to Form S-1/A Registration Statement, Reg. No. 333-124320, filed by Enterprise GP Holdings L.P. on July 22, 2005).
|
3.6
|
Certificate of Amendment to Certificate of Formation of Enterprise Products Holdings LLC (formerly named EPE Holdings, LLC), filed on November 22, 2010 with the Delaware Secretary of State (incorporated by reference to Exhibit 3.5 to Form 8-K filed November 23, 2010).
|
3.7
|
Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products Holdings LLC dated effective as of September 7, 2011 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 8, 2011).
|
3.8
|
Company Agreement of Enterprise Products Operating LLC dated June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 8, 2007).
|
3.9
|
Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
|
3.10
|
Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
|
4.1
|
Form of Common Unit certificate (incorporated by reference to Exhibit A to Exhibit 3.1 to Form 8-K filed August 16, 2011).
|
4.2
|
Indenture, dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
|
4.3
|
First Supplemental Indenture, dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
|
4.4
|
Second Supplemental Indenture, dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
|
4.5
|
Third Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed August 8, 2007).
|
4.6
|
Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 6, 2004).
|
4.7
|
Third Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 6, 2004).
|
4.8
|
Fourth Supplemental Indenture, dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 6, 2004).
|
4.9
|
Fifth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed March 3, 2005).
|
4.10
|
Sixth Supplemental Indenture, dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed March 3, 2005).
|
4.11
|
Eighth Supplemental Indenture, dated as of July 18, 2006, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
|
4.12
|
Ninth Supplemental Indenture, dated as of May 24, 2007, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed May 24, 2007).
|
4.13
|
Tenth Supplemental Indenture, dated as of June 30, 2007, among Enterprise Products Operating L.P., as Original Issuer, Enterprise Products Partners L.P., as Parent Guarantor, Enterprise Products Operating LLC, as New Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
|
4.14
|
Eleventh Supplemental Indenture, dated as of September 4, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed September 5, 2007).
|
4.15
|
Twelfth Supplemental Indenture, dated as of April 3, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed April 3, 2008).
|
4.16
|
Thirteenth Supplemental Indenture, dated as of April 3, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
|
4.17
|
Fourteenth Supplemental Indenture, dated as of December 8, 2008, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8, 2008).
|
4.18
|
Fifteenth Supplemental Indenture, dated as of June 10, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed June 10, 2009).
|
4.19
|
Sixteenth Supplemental Indenture, dated as of October 5, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
|
4.20
|
Seventeenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed October 28, 2009).
|
4.21
|
Eighteenth Supplemental Indenture, dated as of October 27, 2009, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed October 28, 2009).
|
4.22
|
Nineteenth Supplemental Indenture, dated as of May 20, 2010, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed May 20, 2010).
|
4.23
|
Twentieth Supplemental Indenture, dated as of January 13, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 13, 2011).
|
4.24
|
Twenty-First Supplemental Indenture, dated as of August 24, 2011, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 24, 2011).
|
4.25
|
Twenty-Second Supplemental Indenture, dated as of February 15, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.25 to Form 10-Q filed May 10, 2012).
|
4.26
|
Twenty-Third Supplemental Indenture, dated as of August 13, 2012, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Parent Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed August 13, 2012).
|
4.27
|
Form of Global Note representing $350.0 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
|
4.28
|
Form of Global Note representing $499.2 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
|
4.29
|
Form of Global Note representing $500.0 million principal amount of 5.60% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
|
4.30
|
Form of Global Note representing $150.0 million principal amount of 5.60% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
|
4.31
|
Form of Global Note representing $350.0 million principal amount of 6.65% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005).
|
4.32
|
Form of Global Note representing $250.0 million principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed November 4, 2005).
|
4.33
|
Form of Global Note representing $250.0 million principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed November 4, 2005).
|
4.34
|
Form of Junior Subordinated Note, including Guarantee (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
|
4.35
|
Form of Global Note representing $800.0 million principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 9, 2007).
|
4.36
|
Form of Global Note representing $400.0 million principal amount of 5.65% Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed April 3, 2008).
|
4.37
|
Form of Global Note representing $700.0 million principal amount of 6.50% Senior Notes due 2019 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed April 3, 2008).
|
4.38
|
Form of Global Note representing $500.0 million principal amount of 9.75% Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed December 8, 2008).
|
4.39
|
Form of Global Note representing $500.0 million principal amount of 4.60% Senior Notes due 2012 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed June 10, 2009).
|
4.40
|
Form of Global Note representing $500.0 million principal amount of 5.25% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
|
4.41
|
Form of Global Note representing $600.0 million principal amount of 6.125% Senior Notes due 2039 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 5, 2009).
|
4.42
|
Form of Global Note representing $490.5 million principal amount of 7.625% Senior Notes due 2012 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed October 28, 2009).
|
4.43
|
Form of Global Note representing $182.6 million principal amount of 6.125% Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed October 28, 2009).
|
4.44
|
Form of Global Note representing $237.6 million principal amount of 5.90% Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 8-K filed October 28, 2009).
|
4.45
|
Form of Global Note representing $349.7 million principal amount of 6.65% Senior Notes due 2018 with attached Guarantee (incorporated by reference to Exhibit 4.6 to Form 8-K filed October 28, 2009).
|
4.46
|
Form of Global Note representing $399.6 million principal amount of 7.55% Senior Notes due 2038 with attached Guarantee (incorporated by reference to Exhibit 4.7 to Form 8-K filed October 28, 2009).
|
4.47
|
Form of Global Note representing $285.8 million principal amount of 7.000% Junior Subordinated Notes due 2067 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 8-K filed October 28, 2009).
|
4.48
|
Form of Global Note representing $400.0 million principal amount of 3.70% Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
|
4.49
|
Form of Global Note representing $1.0 billion principal amount of 5.20% Senior Notes due 2020 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
|
4.50
|
Form of Global Note representing $600.0 million principal amount of 6.45% Senior Notes due 2040 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed May 20, 2010).
|
4.51
|
Form of Global Note representing $750.0 million principal amount of 3.20% Senior Notes due 2016 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 13, 2011).
|
4.52
|
Form of Global Note representing $750.0 million principal amount of 5.95% Senior Notes due 2041 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 13, 2011).
|
4.53
|
Form of Global Note representing $650.0 million principal amount of 4.05% Senior Notes due 2022 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 24, 2011).
|
4.54
|
Form of Global Note representing $600.0 million principal amount of 5.70% Senior Notes due 2042 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 24, 2011).
|
4.55
|
Form of Global Note representing $750.0 million principal amount of 4.85% Senior Notes due 2042 with attached Guarantee (included in Exhibit 4.25 above).
|
4.56
|
Form of Global Note representing $650.0 million principal amount of 1.25% Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 13, 2012).
|
4.57
|
Form of Global Note representing $1.1 billion principal amount of 4.45% Senior Notes due 2043 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Form 8-K filed August 13, 2012).
|
4.58
|
Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to Form 8-K filed May 24, 2007).
|
4.59
|
First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
|
4.60
|
Replacement Capital Covenant, dated October 27, 2009, among Enterprise Products Operating LLC and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 4.9 to Form 8-K filed October 28, 2009).
|
4.61
|
Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.2 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
|
4.62
|
First Supplemental Indenture, dated February 20, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Subsidiary Guarantors, and First Union National Bank, NA, as Trustee (incorporated by reference to Exhibit 99.3 to the Form 8-K filed by TEPPCO Partners, L.P. on February 20, 2002).
|
4.63
|
Second Supplemental Indenture, dated June 27, 2002, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.6 to the Form 10-Q filed by TEPPCO Partners, L.P. on August 14, 2002).
|
4.64
|
Third Supplemental Indenture, dated January 20, 2003, by and among TEPPCO Partners, L.P. as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.7 to the Form 10-K filed by TEPPCO Partners, L.P. on March 21, 2003).
|
4.65
|
Full Release of Guarantee, dated July 31, 2006, by Wachovia Bank, National Association, as Trustee, in favor of Jonah Gas Gathering Company (incorporated by reference to Exhibit 4.8 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2006).
|
4.66
|
Fourth Supplemental Indenture, dated June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Val Verde Gas Gathering Company, L.P., TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
|
4.67
|
Fifth Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.11 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
|
4.68
|
Sixth Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.12 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
|
4.69
|
Seventh Supplemental Indenture, dated March 27, 2008, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.13 to the Form 10-Q filed by TEPPCO Partners, L.P. on May 8, 2008).
|
4.70
|
Eighth Supplemental Indenture, dated October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
|
4.71
|
Full Release of Guarantee, dated November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.64 to Form 10-K filed on March 1, 2010).
|
4.72
|
Indenture, dated May 14, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 99.1 of the Form 8-K filed by TEPPCO Partners, L.P. on May 15, 2007).
|
4.73
|
First Supplemental Indenture, dated May 18, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on May 18, 2007).
|
4.74
|
Replacement of Capital Covenant, dated May 18, 2007, executed by TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P. in favor of the covered debt holders described therein (incorporated by reference to Exhibit 99.1 to the Form 8-K of TEPPCO Partners, L.P. on May 18, 2007).
|
4.75
|
Second Supplemental Indenture, dated as of June 30, 2007, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Val Verde Gas Gathering Company, L.P., as Existing Subsidiary Guarantors, TE Products Pipeline Company, LLC and TEPPCO Midstream Companies, LLC, as New Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TE Products Pipeline Company, LLC on July 6, 2007).
|
4.76
|
Third Supplemental Indenture, dated as of October 27, 2009, by and among TEPPCO Partners, L.P., as Issuer, TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P., as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by TEPPCO Partners, L.P. on October 28, 2009).
|
4.77
|
Full Release of Guarantee, dated as of November 23, 2009, of TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and Val Verde Gas Gathering Company, L.P. by The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.70 to Form 10-K filed on March 1, 2010).
|
10.1***
|
Enterprise Products 1998 Long-Term Incentive Plan (Amended and Restated as of February 23, 2010) (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 26, 2010).
|
10.2***
|
Form of Option Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan for awards issued before May 7, 2008 (incorporated by reference to Exhibit 10.2 to Form 10-Q filed November 9, 2007).
|
10.3***
|
Form of Option Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan for awards issued on or after May 7, 2008 but before February 23, 2010 (incorporated by reference to Exhibit 10.4 to Form 10-Q filed May 12, 2008).
|
10.4***
|
Amendment to Form of Option Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan for awards issued before February 23, 2010 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed August 9, 2010).
|
10.5***
|
Amendment to Form of Option Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan for awards issued before August 5, 2010 (incorporated by reference to Exhibit 10.2 to Form 10-Q filed August 9, 2010).
|
10.6***
|
Form of Option Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 10-Q filed August 9, 2010).
|
10.7***
|
Form of Employee Restricted Unit Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan for awards issued before February 23, 2010 (incorporated by reference to Exhibit 10.3 to Form 10-Q filed November 9, 2007).
|
10.8***
|
Amendment to Form of Employee Restricted Unit Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan for awards issued before August 5, 2010 (incorporated by reference to Exhibit 10.4 to Form 10-Q filed August 9, 2010).
|
10.9***
|
Form of Employee Restricted Unit Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 10-Q filed August 9, 2010).
|
10.10***
|
Form of Non-Employee Director Restricted Unit Grant Award under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to Form 8-K filed February 26, 2010).
|
10.11***
|
Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (February 23, 2010) (incorporated by reference to Exhibit 10.7 to Form 8-K filed February 26, 2010).
|
10.12***
|
Form of Option Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan for awards issued before February 23, 2010 (incorporated by reference to Exhibit 4.3 to Form S-8 (Commission File No. 333-150680) filed May 6, 2008).
|
10.13***
|
Amendment to Form of Option Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan for awards issued before February 23, 2010 (incorporated by reference to Exhibit 10.9 to Form 10-Q filed August 9, 2010).
|
10.14***
|
Amendment to Form of Option Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan for awards issued after February 23, 2010 and before August 5, 2010 (incorporated by reference to Exhibit 10.10 to Form 10-Q filed August 9, 2010).
|
10.15***
|
Form of Option Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11 to Form 10-Q filed August 9, 2010).
|
10.16***
|
Amendment to Form of Employee Restricted Unit Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan for awards issued before August 5, 2010 (incorporated by reference to Exhibit 10.12 to Form 10-Q filed August 9, 2010).
|
10.17***
|
Form of Employee Restricted Unit Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (incorporated by reference to Exhibit 10.13 to Form 10-Q filed August 9, 2010).
|
10.18***
|
Form of Non-Employee Director Restricted Unit Grant Award under the Amended and Restated 2008 Enterprise Products Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11 to Form 8-K filed February 26, 2010).
|
10.19
|
Distribution Waiver Agreement, dated as of November 22, 2010, by and among Enterprise Products Partners L.P., EPCO Holdings, Inc. and the EPD Unitholder named therein (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 23, 2010).
|
10.20***
|
Retention Agreement between Mr. William Ordemann and Enterprise Products Company dated effective October 1, 2010 (incorporated by reference to Exhibit 10.1 to Form 8-K filed October 14, 2010).
|
10.21***
|
Retention Agreement between Mr. Michael A. Creel and Enterprise Products Company dated effective December 1, 2010 (incorporated by reference to Exhibit 10.1 to Form 8-K filed December 10, 2010).
|
10.22***
|
Retention Agreement between Mr. W. Randall Fowler and Enterprise Products Company dated effective December 1, 2010 (incorporated by reference to Exhibit 10.2 to Form 8-K filed December 10, 2010).
|
10.23***
|
Retention Agreement between Mr. A. James Teague and Enterprise Products Company dated effective December 1, 2010 (incorporated by reference to Exhibit 10.3 to Form 8-K filed December 10, 2010).
|
10.24***
|
Retention Agreement between Mr. Lynn L. Bourdon, III and Enterprise Products Company dated effective October 1, 2010 (incorporated by reference to Exhibit 10.28 to Form 10-K filed February 29, 2012).
|
10.25
|
Revolving Credit Agreement, dated as of September 7, 2011, among Enterprise Products Operating LLC, Canadian Enterprise Gas Products, Ltd, the Lenders party thereto, Wells Fargo Bank National Association, as Administrative Agent, The Royal Bank of Scotland PLC, Mizuho Corporate Bank, Ltd. and The Bank of Nova Scotia, as Co-syndication Agents and JPMorgan Chase Bank, N.A. and Barclays Bank PLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 8, 2011).
|
10.26
|
Guaranty Agreement, dated as of September 7, 2011, by and among Enterprise Products Partners L.P. and Enterprise Products Operating LLC in favor of Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed September 8, 2011).
|
10.27
|
Sixth Amended and Restated Administrative Services Agreement, dated as of September 7, 2011, by and among Enterprise Products Company, EPCO Holdings, Inc., Enterprise Products Holdings LLC, Enterprise Products Partners L.P., Enterprise Products OLPGP, Inc., Enterprise Products Operating LLC, the TEPPCO Parties named therein, Enterprise ETE LLC and the DEP Parties named therein (incorporated by reference to Exhibit 10.3 to Form 8-K filed September 8, 2011).
|
10.28
|
Equity Distribution Agreement, dated May 31, 2012, by and among Enterprise Products Partners L.P., Enterprise Products OLPGP, Inc., Enterprise Products Operating LLC and Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Deutsche Bank Securities Inc., Knight Capital Americas, L.P., Mizuho Securities USA Inc., Raymond James & Associates, Inc., RBS Securities Inc., Scotia Capital (USA) Inc., SunTrust Robinson Humphrey, Inc., UBS Securities LLC and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 1.1 to Form 8-K filed May 31, 2012).
|
12.1#
|
Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2012, 2011, 2010, 2009 and 2008.
|
21.1#
|
List of consolidated subsidiaries as of February 1, 2013.
|
23.1#
|
Consent of Deloitte & Touche LLP.
|
31.1#
|
Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P.'s annual report on Form 10-K for the year ended December 31, 2012.
|
31.2#
|
Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P.'s annual report on Form 10-K for the year ended December 31, 2012.
|
32.1#
|
Sarbanes-Oxley Section 906 certification of Michael A. Creel for Enterprise Products Partners L.P.'s annual report on Form 10-K for the year ended December 31, 2012.
|
32.2#
|
Sarbanes-Oxley Section 906 certification of W. Randall Fowler for Enterprise Products Partners L.P.'s annual report on Form 10-K for the year ended December 31, 2012.
|
101.CAL#
|
XBRL Calculation Linkbase Document
|
101.DEF#
|
XBRL Definition Linkbase Document
|
101.INS#
|
XBRL Instance Document
|
101.LAB#
|
XBRL Labels Linkbase Document
|
101.PRE#
|
XBRL Presentation Linkbase Document
|
101.SCH#
|
XBRL Schema Document
|
*
|
With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file numbers for Enterprise Products Partners L.P., Enterprise GP Holdings L.P, TEPPCO Partners, L.P. and TE Products Pipeline Company, LLC are 1-14323, 1-32610, 1-10403 and 1-13603, respectively.
|
***
|
Identifies management contract and compensatory plan arrangements.
|
#
|
Filed with this report.
|
ENTERPRISE PRODUCTS PARTNERS L.P.
|
|
(A Delaware Limited Partnership)
|
|
|
|
By:
|
Enterprise Products Holdings LLC, as General Partner
|
|
|
|
|
By:
|
/s/ Michael J. Knesek
|
Name:
|
Michael J. Knesek
|
Title:
|
Senior Vice President, Controller and Principal Accounting
Officer of the General Partner
|
Signature
|
|
Title (Position with Enterprise Products Holdings LLC)
|
/s/ Randa Duncan Williams
|
|
Director and Chairman of the Board
|
Randa Duncan Williams
|
|
|
/s/ Thurmon M. Andress
|
|
Director
|
Thurmon M. Andress
|
|
|
/s/ Richard H. Bachmann
|
|
Director
|
Richard H. Bachmann
|
|
|
/s/ E. William Barnett
|
|
Director
|
E. William Barnett
|
|
|
/s/ Larry J. Casey
|
|
Director
|
Larry J. Casey
|
|
|
/s/ Michael A. Creel
|
|
Director and Chief Executive Officer
|
Michael A. Creel
|
|
|
/s/ Dr. Ralph S. Cunningham
|
|
Director
|
Dr. Ralph S. Cunningham
|
|
|
/s/ W. Randall Fowler
|
|
Director, Executive Vice President and Chief Financial Officer
|
W. Randall Fowler
|
|
|
/s/ Charles E. McMahen
|
|
Director
|
Charles E. McMahen
|
|
|
/s/ Rex C. Ross
|
|
Director
|
Rex C. Ross
|
|
|
/s/ Edwin E. Smith
|
|
Director
|
Edwin E. Smith
|
|
|
/s/ Richard S. Snell
|
|
Director
|
Richard S. Snell
|
|
|
/s/ A. James Teague
|
|
Director and Chief Operating Officer
|
A. James Teague
|
|
|
/s/ Michael J. Knesek
|
|
Senior Vice President, Controller and Principal Accounting Officer
|
Michael J. Knesek
|
|
|
|
|
Page No.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
|
December 31,
|
|||||||
ASSETS
|
2012
|
2011
|
||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$
|
16.1
|
$
|
19.8
|
||||
Restricted cash
|
4.3
|
38.5
|
||||||
Accounts receivable – trade, net of allowance for doubtful accounts
of $13.2 at December 31, 2012 and $13.4 at December 31, 2011
|
4,350.9
|
4,501.8
|
||||||
Accounts receivable – related parties
|
2.5
|
43.5
|
||||||
Inventories
|
1,088.4
|
1,111.7
|
||||||
Prepaid and other current assets
|
380.9
|
353.4
|
||||||
Total current assets
|
5,843.1
|
6,068.7
|
||||||
Property, plant and equipment, net
|
24,846.4
|
22,191.6
|
||||||
Investments in unconsolidated affiliates
|
1,394.6
|
1,859.6
|
||||||
Intangible assets, net of accumulated amortization of $1,050.0 at
December 31, 2012 and $990.4 at December 31, 2011
|
1,566.8
|
1,656.2
|
||||||
Goodwill
|
2,086.8
|
2,092.3
|
||||||
Other assets
|
196.7
|
256.7
|
||||||
Total assets
|
$
|
35,934.4
|
$
|
34,125.1
|
||||
|
||||||||
LIABILITIES AND EQUITY
|
||||||||
Current liabilities:
|
||||||||
Current maturities of debt (see Note 12)
|
$
|
1,546.6
|
$
|
500.0
|
||||
Accounts payable – trade
|
764.5
|
773.0
|
||||||
Accounts payable – related parties
|
127.1
|
211.6
|
||||||
Accrued product payables
|
4,476.2
|
5,047.1
|
||||||
Accrued interest
|
300.8
|
288.1
|
||||||
Other current liabilities
|
540.5
|
612.6
|
||||||
Total current liabilities
|
7,755.7
|
7,432.4
|
||||||
Long-term debt (see Note 12)
|
14,655.2
|
14,029.4
|
||||||
Deferred tax liabilities
|
22.5
|
91.2
|
||||||
Other long-term liabilities
|
205.0
|
352.8
|
||||||
Commitments and contingencies (see Note 18)
|
||||||||
Equity: (see Note 13)
|
||||||||
Partners' equity:
|
||||||||
Limited partners:
|
||||||||
Common units (898,813,337 units outstanding at December 31, 2012
and 881,620,418 units outstanding at December 31, 2011)
|
13,439.6
|
12,346.3
|
||||||
Class B units (4,520,431 units outstanding at December 31, 2012 and 2011)
|
118.5
|
118.5
|
||||||
Total limited partners' equity
|
13,558.1
|
12,464.8
|
||||||
Accumulated other comprehensive loss
|
(370.4
|
)
|
(351.4
|
)
|
||||
Total partners' equity
|
13,187.7
|
12,113.4
|
||||||
Noncontrolling interests
|
108.3
|
105.9
|
||||||
Total equity
|
13,296.0
|
12,219.3
|
||||||
Total liabilities and equity
|
$
|
35,934.4
|
$
|
34,125.1
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Revenues:
|
||||||||||||
Third parties
|
$
|
42,509.8
|
$
|
43,537.9
|
$
|
33,040.9
|
||||||
Related parties
|
73.3
|
775.1
|
698.4
|
|||||||||
Total revenues (see Note 14)
|
42,583.1
|
44,313.0
|
33,739.3
|
|||||||||
Costs and expenses:
|
||||||||||||
Operating costs and expenses:
|
||||||||||||
Third parties
|
38,602.2
|
39,553.5
|
30,084.1
|
|||||||||
Related parties
|
765.7
|
1,765.0
|
1,365.2
|
|||||||||
Total operating costs and expenses
|
39,367.9
|
41,318.5
|
31,449.3
|
|||||||||
General and administrative costs:
|
||||||||||||
Third parties
|
78.9
|
72.8
|
82.9
|
|||||||||
Related parties
|
91.4
|
109.0
|
121.9
|
|||||||||
Total general and administrative costs
|
170.3
|
181.8
|
204.8
|
|||||||||
Total costs and expenses (see Note 14)
|
39,538.2
|
41,500.3
|
31,654.1
|
|||||||||
Equity in income of unconsolidated affiliates
|
64.3
|
46.4
|
62.0
|
|||||||||
Operating income
|
3,109.2
|
2,859.1
|
2,147.2
|
|||||||||
Other income (expense):
|
||||||||||||
Interest expense
|
(771.8
|
)
|
(744.1
|
)
|
(741.9
|
)
|
||||||
Interest income
|
0.8
|
1.1
|
1.8
|
|||||||||
Other, net
|
72.6
|
(0.6
|
)
|
2.7
|
||||||||
Total other expense, net
|
(698.4
|
)
|
(743.6
|
)
|
(737.4
|
)
|
||||||
Income before income taxes
|
2,410.8
|
2,115.5
|
1,409.8
|
|||||||||
Benefit from (provision for) income taxes (see Note 16)
|
17.2
|
(27.2
|
)
|
(26.1
|
)
|
|||||||
Net income
|
2,428.0
|
2,088.3
|
1,383.7
|
|||||||||
Net income attributable to noncontrolling interests (see Note 13)
|
(8.1
|
)
|
(41.4
|
)
|
(1,062.9
|
)
|
||||||
Net income attributable to limited partners
|
$
|
2,419.9
|
$
|
2,046.9
|
$
|
320.8
|
||||||
|
||||||||||||
Earnings per unit: (see Note 17)
|
||||||||||||
Basic earnings per unit
|
$
|
2.81
|
$
|
2.48
|
$
|
1.17
|
||||||
Diluted earnings per unit
|
$
|
2.71
|
$
|
2.38
|
$
|
1.15
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Net income
|
$
|
2,428.0
|
$
|
2,088.3
|
$
|
1,383.7
|
||||||
Other comprehensive income (loss):
|
||||||||||||
Cash flow hedges:
|
||||||||||||
Commodity derivative instruments:
|
||||||||||||
Changes in fair value of cash flow hedges
|
17.3
|
(221.9
|
)
|
(76.3
|
)
|
|||||||
Reclassification of losses to net income
|
14.2
|
232.3
|
44.0
|
|||||||||
Interest rate derivative instruments:
|
||||||||||||
Changes in fair value of cash flow hedges
|
(70.2
|
)
|
(333.2
|
)
|
(0.1
|
)
|
||||||
Reclassification of losses to net income
|
16.2
|
6.3
|
25.6
|
|||||||||
Foreign currency derivative instruments:
|
||||||||||||
Changes in fair value of cash flow hedges
|
--
|
--
|
(0.1
|
)
|
||||||||
Reclassification of gains to net income
|
--
|
--
|
(0.3
|
)
|
||||||||
Total cash flow hedges
|
(22.5
|
)
|
(316.5
|
)
|
(7.2
|
)
|
||||||
Foreign currency translation adjustment
|
--
|
--
|
0.9
|
|||||||||
Change in funded status of pension and postretirement plans, net of tax
|
2.5
|
(1.3
|
)
|
0.4
|
||||||||
Proportionate share of other comprehensive income of unconsolidated affiliate
|
1.0
|
--
|
10.2
|
|||||||||
Total other comprehensive income (loss)
|
(19.0
|
)
|
(317.8
|
)
|
4.3
|
|||||||
Comprehensive income
|
2,409.0
|
1,770.5
|
1,388.0
|
|||||||||
Comprehensive income attributable to noncontrolling interests
|
(8.1
|
)
|
(41.4
|
)
|
(1,065.1
|
)
|
||||||
Comprehensive income attributable to limited partners
|
$
|
2,400.9
|
$
|
1,729.1
|
$
|
322.9
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Operating activities:
|
||||||||||||
Net income
|
$
|
2,428.0
|
$
|
2,088.3
|
$
|
1,383.7
|
||||||
Reconciliation of net income to net cash flows provided by operating activities:
|
||||||||||||
Depreciation, amortization and accretion
|
1,104.9
|
1,007.0
|
985.1
|
|||||||||
Non-cash asset impairment charges (see Note 6)
|
63.4
|
27.8
|
8.4
|
|||||||||
Equity in income of unconsolidated affiliates
|
(64.3
|
)
|
(46.4
|
)
|
(62.0
|
)
|
||||||
Distributions received from unconsolidated affiliates
|
116.7
|
156.4
|
191.9
|
|||||||||
Gains attributable to disposal of assets (see Note 20)
|
(86.4
|
)
|
(155.7
|
)
|
(46.7
|
)
|
||||||
Deferred income tax expense (benefit)
|
(66.2
|
)
|
12.1
|
7.9
|
||||||||
Changes in fair market value of derivative instruments
|
(29.5
|
)
|
(25.7
|
)
|
21.6
|
|||||||
Net effect of changes in operating accounts (see Note 20)
|
(582.5
|
)
|
266.9
|
(190.4
|
)
|
|||||||
Other operating activities
|
6.8
|
(0.2
|
)
|
0.5
|
||||||||
Net cash flows provided by operating activities
|
2,890.9
|
3,330.5
|
2,300.0
|
|||||||||
Investing activities:
|
||||||||||||
Capital expenditures
|
(3,621.9
|
)
|
(3,867.5
|
)
|
(2,040.8
|
)
|
||||||
Contributions in aid of construction costs
|
23.4
|
24.9
|
38.7
|
|||||||||
Decrease (increase) in restricted cash
|
34.2
|
60.2
|
(35.0
|
)
|
||||||||
Cash used for business combinations (see Note 10)
|
--
|
--
|
(1,313.9
|
)
|
||||||||
Investments in unconsolidated affiliates
|
(609.5
|
)
|
(30.0
|
)
|
(8.0
|
)
|
||||||
Proceeds from disposal of assets (see Note 20)
|
1,198.8
|
1,053.8
|
105.9
|
|||||||||
Other investing activities
|
(43.8
|
)
|
(19.0
|
)
|
1.5
|
|||||||
Cash used in investing activities
|
(3,018.8
|
)
|
(2,777.6
|
)
|
(3,251.6
|
)
|
||||||
Financing activities:
|
||||||||||||
Borrowings under debt agreements
|
8,363.1
|
8,324.1
|
6,484.4
|
|||||||||
Repayments of debt
|
(6,676.4
|
)
|
(7,375.8
|
)
|
(5,344.4
|
)
|
||||||
Debt issuance costs
|
(21.5
|
)
|
(34.7
|
)
|
(22.5
|
)
|
||||||
Monetization of interest rate derivative instruments (see Note 6)
|
(147.8
|
)
|
(23.2
|
)
|
1.3
|
|||||||
Cash distributions paid to limited partners (see Note 13)
|
(2,178.6
|
)
|
(1,974.3
|
)
|
(307.7
|
)
|
||||||
Cash distributions paid to noncontrolling interests (see Note 13)
|
(13.3
|
)
|
(60.7
|
)
|
(1,467.8
|
)
|
||||||
Cash contributions from noncontrolling interests (see Note 13)
|
6.6
|
8.5
|
1,096.5
|
|||||||||
Net cash proceeds from issuance of common units
|
816.8
|
542.9
|
528.5
|
|||||||||
Other financing activities
|
(24.7
|
)
|
(5.4
|
)
|
(7.2
|
)
|
||||||
Cash provided by (used in) financing activities
|
124.2
|
(598.6
|
)
|
961.1
|
||||||||
Effect of exchange rate changes on cash
|
--
|
--
|
0.7
|
|||||||||
Net change in cash and cash equivalents
|
(3.7
|
)
|
(45.7
|
)
|
9.5
|
|||||||
Cash and cash equivalents, January 1
|
19.8
|
65.5
|
55.3
|
|||||||||
Cash and cash equivalents, December 31
|
$
|
16.1
|
$
|
19.8
|
$
|
65.5
|
|
Partners' Equity
|
|||||||||||||||
|
Limited
Partners
|
Accumulated
Other
Comprehensive
Income (Loss)
|
Noncontrolling
Interests
|
Total
|
||||||||||||
Balance, December 31, 2009
|
$
|
1,972.4
|
$
|
(33.3
|
)
|
$
|
8,534.0
|
$
|
10,473.1
|
|||||||
Net income
|
320.8
|
--
|
1,062.9
|
1,383.7
|
||||||||||||
Cash distributions paid to limited partners
|
(307.7
|
)
|
--
|
--
|
(307.7
|
)
|
||||||||||
Cash distributions paid to noncontrolling interests
|
--
|
--
|
(1,467.8
|
)
|
(1,467.8
|
)
|
||||||||||
Cash contributions from noncontrolling interests
|
--
|
--
|
1,096.5
|
1,096.5
|
||||||||||||
Net cash proceeds from issuance of common units
|
528.5
|
--
|
--
|
528.5
|
||||||||||||
Amortization of fair value of equity-based awards
|
7.6
|
--
|
51.9
|
59.5
|
||||||||||||
Common units issued to EPCO in exchange for equity interest in trucking business
|
1.8
|
--
|
36.0
|
37.8
|
||||||||||||
Common units issued in connection with acquisition of marine shipyard business
|
--
|
--
|
99.7
|
99.7
|
||||||||||||
Issuance of common units pursuant to Holdings Merger (see Note 13)
|
8,883.5
|
(1.3
|
)
|
(8,882.2
|
)
|
--
|
||||||||||
Cash flow hedges
|
--
|
(9.4
|
)
|
2.2
|
(7.2
|
)
|
||||||||||
Other
|
(0.2
|
)
|
11.5
|
(6.6
|
)
|
4.7
|
||||||||||
Balance, December 31, 2010
|
11,406.7
|
(32.5
|
)
|
526.6
|
11,900.8
|
|||||||||||
Net income
|
2,046.9
|
--
|
41.4
|
2,088.3
|
||||||||||||
Cash distributions paid to limited partners
|
(1,974.3
|
)
|
--
|
--
|
(1,974.3
|
)
|
||||||||||
Cash distributions paid to noncontrolling interests
|
--
|
--
|
(60.7
|
)
|
(60.7
|
)
|
||||||||||
Cash contributions from noncontrolling interests
|
--
|
--
|
8.5
|
8.5
|
||||||||||||
Net cash proceeds from issuance of common units
|
542.9
|
--
|
--
|
542.9
|
||||||||||||
Acquisition of noncontrolling interest in subsidiary
|
(5.4
|
)
|
--
|
(9.6
|
)
|
(15.0
|
)
|
|||||||||
Amortization of fair value of equity-based awards
|
50.9
|
--
|
0.1
|
51.0
|
||||||||||||
Issuance of common units pursuant to Duncan Merger (see Note 13)
|
402.8
|
(1.1
|
)
|
(401.7
|
)
|
--
|
||||||||||
Cash flow hedges
|
--
|
(316.5
|
)
|
--
|
(316.5
|
)
|
||||||||||
Other
|
(5.7
|
)
|
(1.3
|
)
|
1.3
|
(5.7
|
)
|
|||||||||
Balance, December 31, 2011
|
12,464.8
|
(351.4
|
)
|
105.9
|
12,219.3
|
|||||||||||
Net income
|
2,419.9
|
--
|
8.1
|
2,428.0
|
||||||||||||
Cash distributions paid to limited partners
|
(2,178.6
|
)
|
--
|
--
|
(2,178.6
|
)
|
||||||||||
Cash distributions paid to noncontrolling interests
|
--
|
--
|
(13.3
|
)
|
(13.3
|
)
|
||||||||||
Cash contributions from noncontrolling interests
|
--
|
--
|
6.6
|
6.6
|
||||||||||||
Net cash proceeds from issuance of common units
|
816.8
|
--
|
--
|
816.8
|
||||||||||||
Amortization of fair value of equity-based awards
|
58.9
|
--
|
--
|
58.9
|
||||||||||||
Cash flow hedges
|
--
|
(22.5
|
)
|
--
|
(22.5
|
)
|
||||||||||
Other
|
(23.7
|
)
|
3.5
|
1.0
|
(19.2
|
)
|
||||||||||
Balance, December 31, 2012
|
$
|
13,558.1
|
$
|
(370.4
|
)
|
$
|
108.3
|
$
|
13,296.0
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Balance at beginning of period
|
$
|
13.4
|
$
|
18.4
|
$
|
16.8
|
||||||
Charged to costs and expenses
|
0.3
|
0.8
|
2.6
|
|||||||||
Acquisition-related additions and other
|
--
|
--
|
1.1
|
|||||||||
Deductions (1)
|
(0.5
|
)
|
(5.8
|
)
|
(2.1
|
)
|
||||||
Balance at end of period
|
$
|
13.2
|
$
|
13.4
|
$
|
18.4
|
||||||
|
||||||||||||
(1) The 2011 deduction amount is primarily due to our reassessment of the allowance for doubtful accounts as a result of improved credit ratings of a customer, which reduced our exposure to potential uncollectibility.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Balance at beginning of period
|
$
|
12.3
|
$
|
12.4
|
$
|
16.7
|
||||||
Charged to costs and expenses
|
13.9
|
9.3
|
2.8
|
|||||||||
Acquisition-related additions and other
|
5.2
|
1.0
|
0.9
|
|||||||||
Deductions
|
(17.7
|
)
|
(10.4
|
)
|
(8.0
|
)
|
||||||
Balance at end of period
|
$
|
13.7
|
$
|
12.3
|
$
|
12.4
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Gain on sales of available-for-sale equity securities of Energy Transfer Equity (1)
|
$
|
68.8
|
$
|
--
|
$
|
--
|
||||||
Distribution income from Energy Transfer Equity
|
4.1
|
--
|
--
|
|||||||||
Other
|
(0.3
|
)
|
(0.6
|
)
|
2.7
|
|||||||
Total
|
$
|
72.6
|
$
|
(0.6
|
)
|
$
|
2.7
|
|||||
|
||||||||||||
(1) See Note 9 for information regarding the liquidation of our investment in limited partnership units of Energy Transfer Equity.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Restricted common unit awards
|
$
|
57.0
|
$
|
47.5
|
$
|
31.5
|
||||||
Unit option awards
|
1.3
|
3.1
|
3.4
|
|||||||||
Other (1)
|
1.7
|
0.3
|
35.5
|
|||||||||
Total compensation expense
|
$
|
60.0
|
$
|
50.9
|
$
|
70.4
|
||||||
|
||||||||||||
(1) Primarily consists of unit appreciation rights ("UARs"), phantom units and similar awards. Also, the amounts presented for 2010 include $31.3 million of compensation expense for awards related to limited partnership interests in the Employee Partnerships, which were liquidated in August 2010.
|
|
Weighted-
|
|||||||
|
Average Grant
|
|||||||
|
Number of
|
Date Fair Value
|
||||||
|
Units
|
per Unit (1)
|
||||||
Enterprise restricted common unit awards:
|
||||||||
Restricted common units at December 31, 2009
|
2,720,882
|
$
|
27.70
|
|||||
Granted (2,5)
|
1,393,925
|
$
|
32.60
|
|||||
Vested (5)
|
(383,628
|
)
|
$
|
25.51
|
||||
Forfeited
|
(169,565
|
)
|
$
|
29.87
|
||||
Restricted common units at December 31, 2010
|
3,561,614
|
$
|
29.78
|
|||||
Granted (3,6)
|
1,414,630
|
$
|
43.66
|
|||||
Vested (6)
|
(924,108
|
)
|
$
|
31.54
|
||||
Forfeited
|
(183,920
|
)
|
$
|
34.27
|
||||
Restricted common units at December 31, 2011
|
3,868,216
|
$
|
34.22
|
|||||
Granted (4,7)
|
1,588,738
|
$
|
51.96
|
|||||
Vested (7)
|
(1,316,603
|
)
|
$
|
34.80
|
||||
Forfeited
|
(246,865
|
)
|
$
|
40.43
|
||||
Restricted common units at December 31, 2012
|
3,893,486
|
$
|
40.87
|
|||||
|
||||||||
Duncan Energy Partners restricted common unit awards:
|
||||||||
Restricted common units at December 31, 2009
|
--
|
$
|
--
|
|||||
Granted (5,8)
|
6,348
|
$
|
25.26
|
|||||
Vested (5)
|
(6,348
|
)
|
$
|
25.26
|
||||
Restricted common units at December 31, 2010
|
--
|
$
|
--
|
|||||
Granted (6,9)
|
3,666
|
$
|
32.56
|
|||||
Vested (6)
|
(3,666
|
)
|
$
|
32.56
|
||||
Restricted common units at September 6, 2011
|
--
|
$
|
--
|
|||||
|
||||||||
Holdings restricted common unit awards:
|
||||||||
Restricted common units at December 31, 2009
|
--
|
$
|
--
|
|||||
Granted (5,10)
|
3,424
|
$
|
41.47
|
|||||
Vested (5)
|
(3,424
|
)
|
$
|
41.47
|
||||
Restricted common units at November 21, 2010
|
--
|
$
|
--
|
|||||
|
||||||||
(1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.
(2) The aggregate grant date fair value of restricted common unit awards issued during 2010 was $45.4 million based on grant date market prices of our common units ranging from $32.00 to $43.18 per unit. An estimated annual forfeiture rate of 4.6% was applied to these awards.
(3) The aggregate grant date fair value of restricted common unit awards issued during 2011 was $61.8 million based on a grant date market price of our common units ranging from $40.54 to $44.67 per unit. An estimated annual forfeiture rate of 4.6% was applied to these awards.
(4) The aggregate grant date fair value of restricted common unit awards issued during 2012 was $82.5 million based on a grant date market price of our common units ranging from $51.92 to $53.54 per unit. An estimated annual forfeiture rate of 3.25% was applied to these awards.
(5) Includes awards granted to the independent directors of the boards of directors of EPGP, DEP GP and Holdings GP as part of their annual compensation for 2010. A total of 6,960, 6,348 and 3,424 restricted common unit awards were issued in February 2010 to the independent directors of EPGP, DEP GP and Holdings GP, respectively, which immediately vested upon issuance.
(6) Includes awards granted to the independent directors of the boards of directors of Enterprise GP and DEP GP as part of their annual compensation for 2011. A total of 10,230 and 3,666 restricted common unit awards were issued in February 2011 to the independent directors of Enterprise GP and DEP GP, respectively, which immediately vested upon issuance.
(7) Includes awards granted to the independent directors of the board of directors of Enterprise GP as part of their annual compensation for 2012. A total of 10,038 restricted common unit awards were issued in February 2012 to the independent directors of Enterprise GP, which immediately vested upon issuance.
(8) The aggregate grant date fair value of restricted common unit awards issued during 2010 denominated in Duncan Energy Partners' common units was $0.2 million based on a grant date market price of Duncan Energy Partners' common units of $25.26 per unit.
(9) The aggregate grant date fair value of restricted common unit awards issued during 2011 denominated in Duncan Energy Partners' common units was $0.1 million based on a grant date market price of Duncan Energy Partners' common units of $32.56 per unit.
(10) The aggregate grant date fair value of restricted common unit awards issued during 2010 denominated in Holdings' units was $0.1 million based on a grant date market price of Holdings' units of $41.47 per unit.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Cash distributions paid to restricted common unit holders
|
$
|
10.5
|
$
|
9.6
|
$
|
8.0
|
||||||
Total intrinsic value of our restricted common unit awards that vested during period
|
$
|
67.0
|
$
|
39.1
|
$
|
13.9
|
|
Weighted-
|
|||||||||||||||
|
Weighted-
|
Average
|
||||||||||||||
|
Average
|
Remaining
|
Aggregate
|
|||||||||||||
|
Number of
|
Strike Price
|
Contractual
|
Intrinsic
|
||||||||||||
|
Units
|
(dollars/unit)
|
Term (in years)
|
Value (1)
|
||||||||||||
Unit option awards at December 31, 2009
|
3,825,920
|
$
|
26.52
|
|||||||||||||
Granted (2)
|
785,000
|
$
|
32.26
|
|||||||||||||
Exercised
|
(857,500
|
)
|
$
|
24.98
|
||||||||||||
Unit option awards at December 31, 2010 and 2011
|
3,753,420
|
$
|
28.08
|
|||||||||||||
Exercised
|
(742,280
|
)
|
$
|
30.77
|
||||||||||||
Forfeited
|
(250,000
|
)
|
$
|
27.45
|
||||||||||||
Unit option awards at December 31, 2012 (3,4)
|
2,761,140
|
$
|
27.41
|
2.0
|
$
|
13.0
|
||||||||||
|
||||||||||||||||
(1) Aggregate intrinsic value reflects fully vested unit option awards at the date indicated.
(2) Aggregate grant date fair value of these unit option awards issued during 2010 was $2.3 million based on the following assumptions: (i) a weighted-average grant date market price of our common units of $32.26 per unit; (ii) weighted-average expected life of options of 4.9 years; (iii) weighted-average risk-free interest rate of 2.5%; (iv) weighted-average expected distribution yield on our common units of 6.9%; and (v) weighted-average expected unit price volatility on our common units of 23.3%. An estimated annual forfeiture rate of 4.6% was applied to awards granted during 2010.
(3) At December 31, 2012 and 2011, we were committed to issue 2,761,140 and 3,753,420, respectively, of our common units if all outstanding unit option awards were exercised. Option awards outstanding at December 31, 2012 include 676,000 awards that vested during 2012 and became exercisable beginning in February 2013. Of the remaining outstanding option awards at December 31, 2012, 1,390,140 and 695,000 will vest in 2013 and 2014, respectively. These unit option awards become exercisable in the calendar year following the year in which they vest.
(4) None of the unit option awards outstanding at December 31, 2012, 2011 and 2010 were exercisable.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Total intrinsic value of unit option awards exercised during period
|
$
|
14.6
|
$
|
--
|
$
|
10.6
|
||||||
Cash received from EPCO in connection with the exercise of unit option awards (1)
|
$
|
10.2
|
$
|
--
|
$
|
7.2
|
||||||
Unit option-related cash reimbursements to EPCO (1)
|
$
|
14.0
|
$
|
--
|
$
|
10.6
|
||||||
(1) For the year ended December 31, 2012, we classified cash receipts from EPCO and reimbursements to EPCO related to the exercise of unit options as a component of other financing activities on our Statement of Consolidated Cash Flows. For comparative purposes, amounts for 2010 have been reclassified to conform to the current year presentation. The reclassification of 2010 amounts had no effect on previously reported cash provided by financing activities for that year.
|
|
UARs Based on Units of
|
|||||||||||
|
Enterprise
|
Holdings
|
Total
|
|||||||||
UARs at December 31, 2009
|
142,196
|
90,000
|
232,196
|
|||||||||
Settled, forfeited or cancelled (1)
|
(107,092
|
)
|
(90,000
|
)
|
(197,092
|
)
|
||||||
Awards assumed by Enterprise in connection with the Holdings Merger (2)
|
135,000
|
--
|
135,000
|
|||||||||
UARs at December 31, 2010
|
170,104
|
--
|
170,104
|
|||||||||
Vested
|
(17,776
|
)
|
--
|
(17,776
|
)
|
|||||||
Cancelled
|
(45,000
|
)
|
--
|
(45,000
|
)
|
|||||||
UARs at December 31, 2011
|
107,328
|
--
|
107,328
|
|||||||||
Vested
|
(107,328
|
)
|
--
|
(107,328
|
)
|
|||||||
UARs at December 31, 2012
|
--
|
--
|
--
|
|||||||||
|
||||||||||||
(1) Prior to the Holdings Merger, the non-employee directors of DEP GP, the general partner of Duncan Energy Partners, were granted 90,000 UARs denominated in Holdings units in connection with certain letter agreements. The compensation expense and associated liability for these UARs was recognized by Enterprise since it owned DEP GP. At the effective date of the Holdings Merger in November 2010, these UARs were settled and $2.5 million in cash was paid to award recipients.
(2) At the effective date of the Holdings Merger, Enterprise assumed 90,000 UARs that had been issued by Holdings GP to its non-employee directors. Since these UARs were denominated in Holdings units, they converted into 135,000 Enterprise UARs based on the 1.5:1 merger exchange ratio.
|
§
|
Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change.
|
§
|
Variable cash flows of a forecasted transaction – In a cash flow hedge, the effective portion of the hedge is reported in other comprehensive income (loss) and is reclassified into earnings when the forecasted transaction affects earnings.
|
Hedged Transaction
|
Number and Type
of Derivatives
Outstanding
|
Notional
Amount
|
Period of
Hedge
|
Rate
Swap
|
Accounting
Treatment
|
|||
Senior Notes AA
|
10 fixed-to-floating swaps
|
$
|
750.0
|
1/2011 to 2/2016
|
3.2% to 1.3%
|
Fair value hedge
|
||
Undesignated swaps
|
6 floating-to-fixed swaps
|
$
|
600.0
|
5/2010 to 7/2014
|
0.4% to 2.0%
|
Mark-to-market
|
Hedged Transaction
|
Number and Type
of Derivatives
Outstanding
|
Notional
Amount
|
Expected
Termination
Date
|
Average Rate
Locked
|
Accounting
Treatment
|
|||||||||
Future debt offering
|
16 forward starting swaps
|
$
|
1,000.0
|
3/2013
|
3.7%
|
|
Cash flow hedge
|
|
Volume (1)
|
Accounting
|
|
Derivative Purpose
|
Current (2)
|
Long-Term (2)
|
Treatment
|
Derivatives designated as hedging instruments:
|
|
|
|
Octane enhancement:
|
|
|
|
Forecasted purchases of NGLs (MMBbls)
|
1.3
|
n/a
|
Cash flow hedge
|
Forecasted sales of octane enhancement products (MMBbls)
|
2.8
|
0.1
|
Cash flow hedge
|
Natural gas marketing:
|
|
|
|
Forecasted sales of natural gas (Bcf)
|
3.2
|
n/a
|
Cash flow hedge
|
Natural gas storage inventory management activities (Bcf)
|
16.2
|
n/a
|
Fair value hedge
|
NGL marketing:
|
|
|
|
Forecasted purchases of NGLs and related hydrocarbon products (MMBbls)
|
2.6
|
n/a
|
Cash flow hedge
|
Forecasted sales of NGLs and related hydrocarbon products (MMBbls)
|
5.5
|
n/a
|
Cash flow hedge
|
Refined products marketing:
|
|
|
|
Forecasted purchases of refined products (MMBbls)
|
0.8
|
n/a
|
Cash flow hedge
|
Forecasted sales of refined products (MMBbls)
|
1.3
|
n/a
|
Cash flow hedge
|
Refined products inventory management activities (MMBbls)
|
0.1
|
n/a
|
Fair value hedge
|
Crude oil marketing:
|
|
|
|
Forecasted purchases of crude oil (MMBbls)
|
3.1
|
n/a
|
Cash flow hedge
|
Forecasted sales of crude oil (MMBbls)
|
6.2
|
n/a
|
Cash flow hedge
|
Derivatives not designated as hedging instruments:
|
|
|
|
Natural gas risk management activities (Bcf) (3,4)
|
138.6
|
24.7
|
Mark-to-market
|
Refined products risk management activities (MMBbls) (4)
|
0.8
|
n/a
|
Mark-to-market
|
Crude oil risk management activities (MMBbls) (4)
|
3.9
|
n/a
|
Mark-to-market
|
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.
(2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is January 2014, October 2013 and October 2015, respectively.
(3) Current volumes include 39.3 Bcf of physical derivative instruments that are predominantly priced at an index plus a premium or minus a discount related to location differences.
(4) Reflects the use of derivative instruments to manage risks associated with transportation, processing and storage assets.
|
§
|
The objective of our natural gas processing strategy was to hedge an amount of gross margin associated with our natural gas processing activities. We achieved this objective by using physical and financial instruments to lock in the purchase prices of natural gas consumed as PTR and the sales prices of the related NGL products. This program consisted of (i) the forward sale of a portion of our expected equity NGL production at fixed prices through December 2012, which was achieved through the use of forward physical sales contracts and commodity derivative instruments and (ii) the purchase of commodity derivative instruments having a notional amount based on the volume of natural gas expected to be consumed as PTR in the production of such equity NGL production.
|
§
|
The objective of our NGL, refined products and crude oil sales hedging program is to hedge the margins of anticipated future sales of inventory by locking in sales prices through the use of forward physical sales contracts and commodity derivative instruments.
|
§
|
The objective of our natural gas and refined products inventory hedging program is to hedge the fair value of natural gas and refined products currently held in inventory by locking in the sales price of the inventory through the use of commodity derivative instruments.
|
|
Asset Derivatives
|
|
Liability Derivatives
|
|
||||||||||||||||
|
December 31, 2012
|
|
December 31, 2011
|
|
December 31, 2012
|
|
December 31, 2011
|
|
||||||||||||
Balance
Sheet
Location
|
Fair
Value
|
Balance
Sheet
Location
|
Fair
Value
|
Balance
Sheet
Location
|
Fair
Value
|
Balance
Sheet
Location
|
Fair
Value
|
|||||||||||||
Derivatives designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Interest rate derivatives
|
Other current
assets
|
|
$
|
19.6
|
|
Other current
assets
|
|
$
|
43.7
|
|
Other current
liabilities
|
|
$
|
175.4
|
|
Other current
liabilities
|
|
$
|
163.6
|
|
Interest rate derivatives
|
Other assets
|
|
|
25.6
|
|
Other assets
|
|
|
44.2
|
|
Other liabilities
|
|
|
--
|
|
Other liabilities
|
|
|
127.1
|
|
Total interest rate derivatives
|
|
|
|
45.2
|
|
|
|
|
87.9
|
|
|
|
|
175.4
|
|
|
|
|
290.7
|
|
Commodity derivatives
|
Other current
assets
|
|
|
45.3
|
|
Other current
assets
|
|
|
20.3
|
|
Other current
liabilities
|
|
|
35.4
|
|
Other current
liabilities
|
|
|
30.3
|
|
Commodity derivatives
|
Other assets
|
|
|
--
|
|
Other assets
|
|
|
--
|
|
Other liabilities
|
|
|
0.5
|
|
Other liabilities
|
|
|
0.2
|
|
Total commodity derivatives
|
|
|
|
45.3
|
|
|
|
|
20.3
|
|
|
|
|
35.9
|
|
|
|
|
30.5
|
|
Total derivatives designated as hedging instruments
|
|
|
$
|
90.5
|
|
|
|
$
|
108.2
|
|
|
|
$
|
211.3
|
|
|
|
$
|
321.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives
|
Other current
assets
|
|
$
|
--
|
|
Other current
assets
|
|
$
|
--
|
|
Other current
liabilities
|
|
$
|
12.2
|
|
Other current
liabilities
|
|
$
|
10.1
|
|
Interest rate derivatives
|
Other assets
|
|
|
--
|
|
Other assets
|
|
|
--
|
|
Other liabilities
|
|
|
5.0
|
|
Other liabilities
|
|
|
10.6
|
|
Total interest rate derivatives
|
|
|
|
--
|
|
|
|
|
--
|
|
|
|
|
17.2
|
|
|
|
|
20.7
|
|
Commodity derivatives
|
Other current
assets
|
|
|
15.7
|
|
Other current
assets
|
|
|
34.4
|
|
Other current
liabilities
|
|
|
8.9
|
|
Other current
liabilities
|
|
|
32.5
|
|
Commodity derivatives
|
Other assets
|
|
|
0.6
|
|
Other assets
|
|
|
12.6
|
|
Other liabilities
|
|
|
0.7
|
|
Other liabilities
|
|
|
2.0
|
|
Total commodity derivatives
|
|
|
|
16.3
|
|
|
|
|
47.0
|
|
|
|
|
9.6
|
|
|
|
|
34.5
|
|
Total derivatives not designated as hedging instruments
|
|
|
$
|
16.3
|
|
|
|
$
|
47.0
|
|
|
|
$
|
26.8
|
|
|
|
$
|
55.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives in Fair Value
Hedging Relationships
|
Location
|
Gain/(Loss) Recognized in
Income on Derivative
|
|||||||||||
|
|
For Year Ended December 31,
|
|||||||||||
|
|
2012
|
2011
|
2010
|
|||||||||
Interest rate derivatives
|
Interest expense
|
$
|
2.7
|
$
|
24.7
|
$
|
16.3
|
||||||
Commodity derivatives
|
Revenue
|
(6.4
|
)
|
17.1
|
3.3
|
||||||||
Total
|
|
$
|
(3.7
|
)
|
$
|
41.8
|
$
|
19.6
|
Derivatives in Fair Value
Hedging Relationships
|
Location
|
Gain/(Loss) Recognized in
Income on Hedged Item
|
|||||||||||
|
|
For Year Ended December 31,
|
|||||||||||
|
|
2012
|
2011
|
2010
|
|||||||||
Interest rate derivatives
|
Interest expense
|
$
|
(2.9
|
)
|
$
|
(24.5
|
)
|
$
|
(16.2
|
)
|
|||
Commodity derivatives
|
Revenue
|
19.1
|
(14.9
|
)
|
(2.6
|
)
|
|||||||
Total
|
|
$
|
16.2
|
$
|
(39.4
|
)
|
$
|
(18.8
|
)
|
Derivatives in Cash Flow
Hedging Relationships
|
Change in Value
Recognized in Other Comprehensive Income/(Loss) on
Derivative (Effective Portion)
|
|||||||||||
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Interest rate derivatives (1)
|
$
|
(70.2
|
)
|
$
|
(333.2
|
)
|
$
|
(0.1
|
)
|
|||
Commodity derivatives – Revenue (2)
|
31.0
|
(192.3
|
)
|
(7.7
|
)
|
|||||||
Commodity derivatives – Operating costs
and expenses
|
(13.7
|
)
|
(29.6
|
)
|
(68.6
|
)
|
||||||
Foreign currency derivatives
|
--
|
--
|
(0.1
|
)
|
||||||||
Total
|
$
|
(52.9
|
)
|
$
|
(555.1
|
)
|
$
|
(76.5
|
)
|
|||
|
||||||||||||
(1) The increase in other comprehensive loss in 2011 and 2012 was primarily due to the impact of decreases in forward London Interbank Offered Rates ("LIBOR") on our forward starting interest rate swap portfolio.
(2) The increase in other comprehensive loss in 2011 was primarily due to the impact of rising commodity prices on our cash flow hedges associated with physical future deliveries of crude oil, refined products and NGLs.
|
Derivatives in Cash Flow
Hedging Relationships
|
Location
|
Gain/(Loss) Reclassified
from Accumulated Other Comprehensive
Income/(Loss) to Income (Effective Portion)
|
|||||||||||
|
|
For Year Ended December 31,
|
|||||||||||
|
|
2012
|
2011
|
2010
|
|||||||||
Interest rate derivatives
|
Interest expense
|
$
|
(16.2
|
)
|
$
|
(6.3
|
)
|
$
|
(25.6
|
)
|
|||
Commodity derivatives
|
Revenue
|
10.1
|
(218.4
|
)
|
2.1
|
||||||||
Commodity derivatives
|
Operating costs and expenses
|
(24.3
|
)
|
(13.9
|
)
|
(46.1
|
)
|
||||||
Foreign currency derivatives
|
Other expense
|
--
|
--
|
0.3
|
|||||||||
Total
|
|
$
|
(30.4
|
)
|
$
|
(238.6
|
)
|
$
|
(69.3
|
)
|
Derivatives in Cash Flow
Hedging Relationships
|
Location
|
Gain/(Loss) Recognized in Income on
Derivative (Ineffective Portion)
|
|||||||||||
|
|
For Year Ended December 31,
|
|||||||||||
|
|
2012
|
2011
|
2010
|
|||||||||
Interest rate derivatives
|
Interest expense
|
$
|
--
|
$
|
--
|
$
|
(0.1
|
)
|
|||||
Commodity derivatives
|
Revenue
|
--
|
0.2
|
--
|
|||||||||
Commodity derivatives
|
Operating costs and expenses
|
0.3
|
(0.3
|
)
|
(0.8
|
)
|
|||||||
Total
|
|
$
|
0.3
|
$
|
(0.1
|
)
|
$
|
(0.9
|
)
|
Derivatives Not Designated as
Hedging Instruments
|
Location
|
Gain/(Loss) Recognized in
Income on Derivative
|
|||||||||||
|
|
For Year Ended December 31,
|
|||||||||||
|
|
2012
|
2011
|
2010
|
|||||||||
Interest rate derivatives
|
Interest expense
|
$
|
(5.6
|
)
|
$
|
(18.5
|
)
|
$
|
(20.1
|
)
|
|||
Commodity derivatives
|
Revenue
|
22.7
|
39.9
|
24.4
|
|||||||||
Commodity derivatives
|
Operating costs and expense
|
(2.8
|
)
|
(3.7
|
)
|
--
|
|||||||
Foreign currency derivatives
|
Other expense
|
--
|
(0.5
|
)
|
0.3
|
||||||||
Total
|
|
$
|
14.3
|
$
|
17.2
|
$
|
4.6
|
§
|
Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the New York Mercantile Exchange). Our Level 1 fair values consist of financial assets and liabilities such as exchange-traded commodity derivative instruments.
|
§
|
Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions (i) are observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity derivative instruments such as forwards, swaps and other instruments transacted on an exchange or over-the-counter and interest rate derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations. The fair value of our interest rate derivatives are determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements.
|
§
|
Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect management's ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available to us in the circumstances, which might include our internally developed data. Level 3 inputs are typically used in connection with internally developed valuation methodologies where we make our best estimate of an instrument's fair value. Our Level 3 fair values primarily consist of ethane, propane, normal butane and natural gasoline-based contracts with terms greater than one year and certain options used to hedge natural gas storage inventory and transportation capacities. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments.
|
|
2012 Fair Value Measurements Using
|
|||||||||||||||
|
Quoted Prices
|
|||||||||||||||
|
in Active
|
Significant
|
||||||||||||||
|
Markets for
|
Other
|
Significant
|
Carrying
|
||||||||||||
|
Identical Assets
|
Observable
|
Unobservable
|
Value
|
||||||||||||
|
and Liabilities
|
Inputs
|
Inputs
|
at December 31,
|
||||||||||||
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
2012
|
||||||||||||
Financial assets:
|
||||||||||||||||
Interest rate derivatives
|
$
|
--
|
$
|
45.2
|
$
|
--
|
$
|
45.2
|
||||||||
Commodity derivatives
|
11.4
|
47.8
|
2.4
|
61.6
|
||||||||||||
Total
|
$
|
11.4
|
$
|
93.0
|
$
|
2.4
|
$
|
106.8
|
||||||||
|
||||||||||||||||
Financial liabilities:
|
||||||||||||||||
Interest rate derivatives
|
$
|
--
|
$
|
192.6
|
$
|
--
|
$
|
192.6
|
||||||||
Commodity derivatives
|
13.1
|
28.5
|
3.9
|
45.5
|
||||||||||||
Total
|
$
|
13.1
|
$
|
221.1
|
$
|
3.9
|
$
|
238.1
|
|
2011 Fair Value Measurements Using
|
|||||||||||||||
|
Quoted Prices
|
|||||||||||||||
|
in Active
|
Significant
|
||||||||||||||
|
Markets for
|
Other
|
Significant
|
Carrying
|
||||||||||||
|
Identical Assets
|
Observable
|
Unobservable
|
Value
|
||||||||||||
|
and Liabilities
|
Inputs
|
Inputs
|
at December 31,
|
||||||||||||
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
2011
|
||||||||||||
Financial assets:
|
||||||||||||||||
Interest rate derivatives
|
$
|
--
|
$
|
87.9
|
$
|
--
|
$
|
87.9
|
||||||||
Commodity derivatives
|
28.4
|
38.1
|
0.8
|
67.3
|
||||||||||||
Total
|
$
|
28.4
|
$
|
126.0
|
$
|
0.8
|
$
|
155.2
|
||||||||
|
||||||||||||||||
Financial liabilities:
|
||||||||||||||||
Interest rate derivatives
|
$
|
--
|
$
|
311.4
|
$
|
--
|
$
|
311.4
|
||||||||
Commodity derivatives
|
29.9
|
34.7
|
0.4
|
65.0
|
||||||||||||
Total
|
$
|
29.9
|
$
|
346.1
|
$
|
0.4
|
$
|
376.4
|
|
|
For Year Ended December 31,
|
|||||||
Location |
2012
|
2011
|
|||||||
Balance, January 1
|
|
$
|
0.4
|
$
|
(25.9
|
)
|
|||
Total gains (losses) included in:
|
|
||||||||
Net income (1)
|
Revenue
|
(2.9
|
)
|
2.3
|
|||||
Other comprehensive income (loss)
|
Commodity derivative instruments – changes in fair value of cash flow hedges
|
10.1
|
16.2
|
||||||
Settlements
|
|
0.8
|
(2.0
|
)
|
|||||
Transfers out of Level 3 (2)
|
|
(9.9
|
)
|
9.8
|
|||||
Balance, December 31
|
|
$
|
(1.5
|
)
|
$
|
0.4
|
|||
|
|
||||||||
(1) There were $1.9 million of unrealized losses and $2.6 million of unrealized gains included in these amounts for the years ended December 31, 2012 and 2011, respectively.
(2) Transfers out of Level 3 into Level 2 during 2012 were due to shorter remaining transaction maturities falling inside of the Level 2 range during the fourth quarter. Transfers out of Level 3 into Level 2 during 2011 were primarily due to the change in observability of forward NGL prices.
|
|
Fair Value
|
|
|
|
|||||||
|
Financial
Assets
|
Financial
Liabilities
|
Valuation
Techniques
|
Unobservable
Input
|
Range
|
||||||
Commodity derivatives – Crude oil
|
$
|
2.4
|
$
|
3.9
|
Discounted cash flow
|
Forward commodity prices
|
$75.62-$92.28/barrel
|
§
|
We recorded a $2.6 million impairment charge in connection with the removal of certain pipeline terminal assets classified as property, plant and equipment. The total carrying value of the pipeline terminal prior to the write-down was $4.8 million and the estimated fair value of the remaining terminal assets to be held and used was $2.2 million based on management's assumptions regarding their current market values (Level 3).
|
§
|
We recorded $4.3 million of impairment charges in connection with sales of certain marine transportation assets and an offshore pipeline lateral that were classified as property, plant and equipment. These assets were sold as of December 31, 2012.
|
§
|
We recorded $56.5 million of impairment charges primarily due to the abandonment of certain pipeline and natural gas processing assets classified as property, plant and equipment. Of this amount, $29.2 million relates to the abandonment of certain gathering pipeline segments of our Texas Intrastate System, $10.6 million relates to the abandonment of certain crude oil pipeline segments in Texas, and $5.7 million relates to the write-off of our undivided interest in the Yscloskey natural gas processing plant following the planned closure of this facility due to damage caused by Hurricane Isaac in August 2012. Of the assets written-off, management estimated that the salvage value of certain pipeline segments was $0.8 million based on current market values (Level 3).
|
|
Fair Value Measurements Using
|
|||||||||||||||||||
|
Quoted Prices
|
Significant
|
||||||||||||||||||
|
Carrying
|
in Active
|
Other
|
Significant
|
||||||||||||||||
|
Value at
|
Markets for
|
Observable
|
Unobservable
|
Total Non-Cash
|
|||||||||||||||
|
December 31,
|
Identical Assets
|
Inputs
|
Inputs
|
Impairment
|
|||||||||||||||
|
2012
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
Loss
|
|||||||||||||||
Impairment of long-lived assets held and used
|
$
|
2.2
|
$
|
--
|
$
|
--
|
$
|
2.2
|
$
|
2.6
|
||||||||||
Impairment of long-lived assets disposed of by sale
|
--
|
--
|
--
|
--
|
4.3
|
|||||||||||||||
Impairment of long-lived assets disposed of
other than by sale
|
0.8
|
--
|
--
|
0.8
|
56.5
|
|||||||||||||||
Total
|
$
|
63.4
|
§
|
We recorded an $11.1 million impairment charge to recognize a decline in value of certain spare parts classified as a component of prepaid and other current assets (held and used). The total carrying value of the spare parts prior to the write-down was $13.8 million and the estimated fair value of the spare parts
|
inventory was $2.7 million based on management's assumptions regarding their current market values (Level 3).
|
§
|
We recorded $16.4 million of impairment charges primarily due to the abandonment of certain pipeline and storage assets classified as property, plant and equipment. Of this amount, $9.1 million relates to the abandonment of certain underground NGL storage caverns located in Texas, Mississippi, Utah and Ohio and $5.1 million relates to the abandonment of certain gathering pipeline segments of our Texas Intrastate System.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
NGL Pipelines & Services
|
$
|
16.3
|
$
|
11.3
|
$
|
2.8
|
||||||
Onshore Natural Gas Pipelines & Services
|
29.2
|
10.4
|
5.2
|
|||||||||
Onshore Crude Oil Pipelines & Services
|
10.6
|
--
|
--
|
|||||||||
Offshore Pipelines & Services
|
4.0
|
5.5
|
--
|
|||||||||
Petrochemical & Refined Products Services
|
3.3
|
0.6
|
0.4
|
|||||||||
Total non-cash impairment charges
|
$
|
63.4
|
$
|
27.8
|
$
|
8.4
|
|
December 31,
|
|||||||
|
2012
|
2011
|
||||||
NGLs
|
$
|
594.3
|
$
|
563.6
|
||||
Petrochemicals and refined products
|
304.5
|
443.4
|
||||||
Crude oil
|
119.4
|
39.2
|
||||||
Natural gas
|
70.2
|
65.5
|
||||||
Total
|
$
|
1,088.4
|
$
|
1,111.7
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Cost of sales (1)
|
$
|
36,015.5
|
$
|
38,292.6
|
$
|
28,723.1
|
||||||
Lower of cost or market adjustments
|
$
|
22.1
|
$
|
9.5
|
$
|
7.9
|
||||||
(1) Cost of sales is a component of "Operating costs and expenses," as presented on our Statements of Consolidated Operations. Year-to-year fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.
|
Estimated
Useful Life
in Years
|
December 31,
|
|||||||||||
|
2012
|
2011
|
||||||||||
Plants, pipelines and facilities (1)
|
3-45 (6)
|
|
$
|
25,382.4
|
$
|
22,354.4
|
||||||
Underground and other storage facilities (2)
|
5-40 (7) |
|
1,826.3
|
1,388.6
|
||||||||
Platforms and facilities (3)
|
20-31 |
635.2
|
637.5
|
|||||||||
Transportation equipment (4)
|
3-10 |
136.2
|
151.5
|
|||||||||
Marine vessels (5)
|
15-30 |
695.0
|
615.9
|
|||||||||
Land
|
167.2
|
136.1
|
||||||||||
Construction in progress
|
2,113.1
|
2,145.6
|
||||||||||
Total
|
30,955.4
|
27,429.6
|
||||||||||
Less accumulated depreciation
|
6,109.0
|
5,238.0
|
||||||||||
Property, plant and equipment, net
|
$
|
24,846.4
|
$
|
22,191.6
|
||||||||
|
||||||||||||
(1) Plants and pipelines include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment and related assets.
(2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets.
(3) Platforms and facilities include offshore platforms and related facilities and other associated assets located in the Gulf of Mexico.
(4) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations.
(5) Marine vessels include tow boats, barges and related equipment used in our marine transportation business.
(6) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings, 20-40 years; and laboratory and shop equipment, 5-35 years.
(7) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Depreciation expense (1)
|
$
|
900.5
|
$
|
776.6
|
$
|
745.7
|
||||||
Capitalized interest (2)
|
116.8
|
106.7
|
47.2
|
|||||||||
(1) Depreciation expense is a component of "Costs and expenses" as presented on our Statements of Consolidated Operations.
(2) We capitalize interest cost incurred on funds used to construct property, plant and equipment. The capitalized interest cost is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life as a component of depreciation expense. See Note 20 for information regarding cash payments for interest.
|
ARO liability balance, December 31, 2010
|
$
|
97.1
|
||
Liabilities incurred
|
0.7
|
|||
Liabilities settled
|
(7.3
|
)
|
||
Revisions in estimated cash flows
|
15.0
|
|||
Accretion expense
|
6.5
|
|||
ARO liability balance, December 31, 2011
|
112.0
|
|||
Liabilities incurred
|
1.7
|
|||
Liabilities settled
|
(27.8
|
)
|
||
Revisions in estimated cash flows
|
13.7
|
|||
Accretion expense
|
5.6
|
|||
ARO liability balance, December 31, 2012
|
$
|
105.2
|
2013
|
2014
|
2015
|
2016
|
2017
|
||||||||||||||
$
|
6.2
|
$
|
6.5
|
$
|
6.3
|
$
|
6.6
|
$
|
7.1
|
Ownership
Interest at
December 31,
2012
|
December 31,
|
|||||||||||
|
2012
|
2011
|
||||||||||
NGL Pipelines & Services:
|
||||||||||||
Venice Energy Service Company, L.L.C. ("VESCO")
|
13.1% |
|
$
|
29.6
|
$
|
35.5
|
||||||
K/D/S Promix, L.L.C. ("Promix")
|
50% |
|
46.9
|
40.7
|
||||||||
Baton Rouge Fractionators LLC ("BRF")
|
32.2%
|
|
20.2
|
21.0
|
||||||||
Skelly-Belvieu Pipeline Company, L.L.C. ("Skelly-Belvieu")
|
50%
|
|
38.2
|
35.0
|
||||||||
Texas Express Pipeline LLC ("Texas Express")
|
35%
|
|
144.4
|
13.9
|
||||||||
Texas Express Gathering LLC ("TEG")
|
45%
|
|
20.9
|
--
|
||||||||
Front Range Pipeline LLC ("Front Range")
|
33.3%
|
|
24.4
|
--
|
||||||||
Onshore Natural Gas Pipelines & Services:
|
||||||||||||
Evangeline (1)
|
--
|
--
|
4.4
|
|||||||||
White River Hub, LLC ("White River Hub")
|
50%
|
|
24.9
|
25.7
|
||||||||
Onshore Crude Oil Pipelines & Services:
|
||||||||||||
Seaway Crude Pipeline Company LLC ("Seaway")
|
50%
|
|
341.4
|
170.7
|
||||||||
Eagle Ford Pipeline LLC ("Eagle Ford Crude Oil Pipeline")
|
50%
|
|
152.4
|
--
|
||||||||
Offshore Pipelines & Services:
|
||||||||||||
Poseidon Oil Pipeline Company, L.L.C. ("Poseidon")
|
36%
|
|
47.3
|
55.4
|
||||||||
Cameron Highway Oil Pipeline Company ("Cameron Highway")
|
50%
|
|
220.0
|
222.8
|
||||||||
Deepwater Gateway, L.L.C. ("Deepwater Gateway")
|
50%
|
|
90.0
|
94.6
|
||||||||
Neptune Pipeline Company, L.L.C. ("Neptune")
|
25.7%
|
|
46.8
|
51.1
|
||||||||
Southeast Keathley Canyon Pipeline Company L.L.C. ("SEKCO")
|
50%
|
|
74.9
|
1.0
|
||||||||
Petrochemical & Refined Products Services:
|
||||||||||||
Baton Rouge Propylene Concentrator, LLC ("BRPC")
|
30%
|
|
8.5
|
9.5
|
||||||||
Centennial Pipeline LLC ("Centennial")
|
50%
|
|
60.8
|
51.8
|
||||||||
Other (2)
|
Various
|
3.0
|
3.4
|
|||||||||
Other Investments:
|
||||||||||||
Energy Transfer Equity (3)
|
--
|
--
|
1,023.1
|
|||||||||
Total
|
$
|
1,394.6
|
$
|
1,859.6
|
||||||||
|
||||||||||||
(1) In June 2012, we acquired the remaining ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively "Evangeline") and they became wholly owned subsidiaries of ours.
(2) Other unconsolidated affiliates include a 50% interest in a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas and a 25% interest in a company that provides logistics communications solutions between petroleum pipelines and their customers.
(3) See "Other Investments" within this Note 9 for information regarding the sale of our ownership interests in Energy Transfer Equity.
|
§
|
VESCO owns a natural gas processing facility and related assets located in south Louisiana.
|
§
|
Promix owns an NGL fractionation facility and related storage and pipeline assets 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. The Skelly-Belvieu Pipeline receives NGLs through a pipeline interconnect with our Mid-America Pipeline System in Skellytown, Texas.
|
§
|
Texas Express was formed in September 2011 to construct a new NGL pipeline (the "Texas Express Pipeline") that will originate in Skellytown, Texas and extend approximately 580 miles to our NGL fractionation and storage facilities in Mont Belvieu, Texas. The Texas Express Pipeline is expected to begin service in the second quarter of 2013.
|
§
|
TEG was formed in April 2012 to construct two NGL gathering systems that will connect to the Texas Express Pipeline. Enbridge Inc. will construct and operate the systems, which are expected to begin service in the second quarter of 2013.
|
§
|
Front Range was formed in April 2012 to construct a new NGL pipeline that will originate in the Denver-Julesburg Basin in Weld County, Colorado and extend 435 miles to Skellytown, Texas. We will construct and operate the pipeline, which is expected to begin service in the fourth quarter of 2013.
|
§
|
Seaway owns a pipeline that connects the Cushing, Oklahoma hub with markets in Southeast Texas. In November 2011, we and Enbridge Holdings (Seaway) L.L.C., our joint venture partner in Seaway, initiated a project to reverse the direction of crude oil flows to enable the pipeline to transport oil from the Cushing hub to U.S. Gulf Coast refineries. In June 2012, the initial phase of this reversal project was completed and Seaway made its first delivery of crude oil to the Texas Gulf Coast from Cushing. The second phase of the reversal project, which entailed construction of additional pump stations and other modifications, was completed in January 2013 and is expected to increase the pipeline's throughput capacity.
|
§
|
Eagle Ford Pipeline LLC was formed in August 2012 to provide crude oil pipeline services to producers in South Texas. The joint venture will include a 140-mile crude oil and condensate line extending from Gardendale, Texas in LaSalle County to Three Rivers, Texas in Live Oak County and continuing on to Corpus Christi, Texas, and a newly constructed 35-mile pipeline segment from Three Rivers to our Lyssy, Texas station in Wilson County. The pipeline system, which is currently under construction, will include operational storage across the system and a marine terminal facility. Segments of the new pipeline system are expected to be placed into service in the first quarter of 2013, with the balance of the system expected to be placed into service in the third quarter of 2013. Plains All American Pipeline, L.P., our joint venture partner in this investment, will serve as operator of the pipeline system.
|
§
|
Poseidon owns a crude oil pipeline that transports crude oil production from the outer continental shelf and deepwater areas of the Gulf of Mexico offshore Louisiana to onshore facilities in south Louisiana.
|
§
|
Cameron Highway owns a crude oil pipeline that transports crude oil production from deepwater areas of the Gulf of Mexico, primarily the Green Canyon area, for delivery to refineries and terminals in southeast Texas.
|
§
|
Deepwater Gateway owns an offshore platform that processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of Mexico.
|
§
|
Neptune owns the Manta Ray Offshore Gathering System and Nautilus System, both of which are natural gas pipeline systems located in the Gulf of Mexico.
|
§
|
SEKCO was formed in December 2011 to construct a 149-mile crude oil gathering pipeline serving the Lucius oil and gas field located in the southern Keathley Canyon area of the deepwater central Gulf of Mexico. The SEKCO Oil Pipeline is expected to begin service by mid-2014.
|
§
|
BRPC owns a propylene fractionation facility located in south Louisiana.
|
§
|
Centennial owns an interstate refined products pipeline extending from the upper Texas Gulf Coast to central Illinois that effectively loops our TE Products Pipeline, which provides us with incremental transportation capacity into Mid-continent markets.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
NGL Pipelines & Services
|
$
|
15.9
|
$
|
21.8
|
$
|
17.7
|
||||||
Onshore Natural Gas Pipelines & Services
|
4.4
|
5.5
|
4.6
|
|||||||||
Onshore Crude Oil Pipelines & Services
|
32.6
|
(4.1
|
)
|
6.7
|
||||||||
Offshore Pipelines & Services
|
26.9
|
27.1
|
44.8
|
|||||||||
Petrochemical & Refined Products Services (1)
|
(17.9
|
)
|
(18.7
|
)
|
(9.0
|
)
|
||||||
Other Investments (2)
|
2.4
|
14.8
|
(2.8
|
)
|
||||||||
Total
|
$
|
64.3
|
$
|
46.4
|
$
|
62.0
|
||||||
|
||||||||||||
(1) Losses are primarily attributable to our investment in Centennial. As a result of a trend in declining earnings, we estimated the fair value of this equity-method investment during each of the last three fiscal years. Our estimates, based on a combination of the market and income approaches, indicate that the fair value of this investment remains substantially in excess of its carrying value.
(2) With respect to the year ended December 31, 2012, the amount presented reflects our equity in the income of Energy Transfer Equity from January 1, 2012 to January 18, 2012.
|
|
December 31,
|
|||||||
|
2012
|
2011
|
||||||
NGL Pipelines & Services
|
$
|
28.9
|
$
|
24.7
|
||||
Onshore Crude Oil Pipelines & Services
|
18.5
|
19.2
|
||||||
Offshore Pipelines & Services
|
13.6
|
14.8
|
||||||
Petrochemical & Refined Products Services
|
2.7
|
2.9
|
||||||
Other Investments (1)
|
--
|
1,119.0
|
||||||
Total
|
$
|
63.7
|
$
|
1,180.6
|
||||
|
||||||||
(1) On January 18, 2012, we discontinued using the equity method to account for our investment in Energy Transfer Equity common units and began accounting for this investment as an available-for-sale security. As a result, we no longer had any excess cost amounts associated with this investment. These excess cost amounts were attributable to various factors, including fixed assets, incentive distribution rights, amortizable intangible assets and equity method goodwill.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
NGL Pipelines & Services
|
$
|
1.0
|
$
|
1.0
|
$
|
0.9
|
||||||
Onshore Crude Oil Pipelines & Services
|
0.7
|
0.7
|
0.7
|
|||||||||
Offshore Pipelines & Service
|
1.2
|
1.2
|
1.3
|
|||||||||
Petrochemical & Refined Products Services
|
0.2
|
0.1
|
1.0
|
|||||||||
Other Investments (1)
|
0.3
|
31.5
|
36.3
|
|||||||||
Total
|
$
|
3.4
|
$
|
34.5
|
$
|
40.2
|
||||||
|
||||||||||||
(1) Reflects amortization of excess cost amounts related to our investment in Energy Transfer Equity through January 18, 2012, which is the date we ceased using the equity method to account for this investment.
|
2013
|
2014
|
2015
|
2016
|
2017
|
||||||||||||||
$
|
3.3
|
$
|
3.3
|
$
|
3.3
|
$
|
3.3
|
$
|
3.3
|
|
At December 31,
|
|||||||||||
|
2012
|
2011
|
||||||||||
BALANCE SHEET DATA:
|
||||||||||||
Current assets
|
$
|
254.7
|
$
|
1,680.3
|
||||||||
Property, plant and equipment, net
|
2,911.3
|
16,413.5
|
||||||||||
Other assets
|
3.2
|
4,893.7
|
||||||||||
Total assets
|
$
|
3,169.2
|
$
|
22,987.5
|
||||||||
|
||||||||||||
Current liabilities
|
$
|
276.3
|
$
|
1,955.7
|
||||||||
Other liabilities
|
272.1
|
11,897.1
|
||||||||||
Combined equity
|
2,620.8
|
9,134.7
|
||||||||||
Total liabilities and combined equity
|
$
|
3,169.2
|
$
|
22,987.5
|
||||||||
|
||||||||||||
|
For Year Ended December 31,
|
|||||||||||
|
2012 |
2011
|
2010
|
|||||||||
INCOME STATEMENT DATA:
|
||||||||||||
Revenues
|
$
|
670.1
|
$
|
9,119.9
|
$
|
7,437.0
|
||||||
Operating income
|
213.7
|
1,393.4
|
1,241.8
|
|||||||||
Net income
|
174.9
|
458.1
|
386.8
|
NGL Pipelines & Services
|
$
|
105.6
|
||
Onshore Natural Gas Pipelines & Services
|
1,111.1
|
|||
Onshore Crude Oil Pipelines & Services
|
10.2
|
|||
Petrochemical & Refined Products Services
|
87.0
|
|||
Total
|
$
|
1,313.9
|
Assets acquired in business combinations:
|
||||
Current assets
|
$
|
3.3
|
||
Property, plant and equipment, net
|
421.4
|
|||
Intangible assets
|
907.6
|
|||
Total assets acquired
|
1,332.3
|
|||
Liabilities assumed in business combinations:
|
||||
Current liabilities
|
(0.4
|
)
|
||
Long-term debt
|
(1.3
|
)
|
||
Other long-term liabilities
|
(0.9
|
)
|
||
Total liabilities assumed
|
(2.6
|
)
|
||
Total assets acquired plus liabilities assumed
|
1,329.7
|
|||
Fair value of 2,329,639 of our units issued as consideration
|
99.7
|
|||
Total cash used for business combinations
|
1,313.9
|
|||
Residual Goodwill (see Note 11)
|
$
|
83.9
|
Pro forma earnings data:
|
||||
Revenues
|
$
|
33,804.7
|
||
Costs and expenses
|
31,713.4
|
|||
Operating income
|
2,153.3
|
|||
Net income
|
1,388.2
|
|||
Net income attributable to limited partners
|
321.0
|
|||
Basic earnings per unit:
|
||||
As reported basic units outstanding
|
274.5
|
|||
Pro forma basic units outstanding
|
274.5
|
|||
As reported basic earnings per unit
|
$
|
1.17
|
||
Pro forma basic earnings per unit
|
$
|
1.17
|
||
Diluted earnings per unit:
|
||||
As reported diluted units outstanding
|
278.5
|
|||
Pro forma diluted units outstanding
|
278.5
|
|||
As reported diluted earnings per unit
|
$
|
1.15
|
||
Pro forma diluted earnings per unit
|
$
|
1.15
|
|
December 31, 2012
|
December 31, 2011
|
||||||||||||||||||||||
|
Gross
Value
|
Accumulated
Amortization
|
Carrying
Value
|
Gross
Value
|
Accumulated
Amortization
|
Carrying
Value
|
||||||||||||||||||
NGL Pipelines & Services:
|
||||||||||||||||||||||||
Customer relationship intangibles
|
$
|
340.8
|
$
|
(147.6
|
)
|
$
|
193.2
|
$
|
340.8
|
$
|
(128.2
|
)
|
$
|
212.6
|
||||||||||
Contract-based intangibles
|
284.6
|
(157.2
|
)
|
127.4
|
298.4
|
(169.7
|
)
|
128.7
|
||||||||||||||||
Segment total
|
625.4
|
(304.8
|
)
|
320.6
|
639.2
|
(297.9
|
)
|
341.3
|
||||||||||||||||
Onshore Natural Gas Pipelines & Services:
|
||||||||||||||||||||||||
Customer relationship intangibles
|
1,163.6
|
(250.0
|
)
|
913.6
|
1,163.6
|
(209.7
|
)
|
953.9
|
||||||||||||||||
Contract-based intangibles
|
466.1
|
(311.8
|
)
|
154.3
|
464.8
|
(290.9
|
)
|
173.9
|
||||||||||||||||
Segment total
|
1,629.7
|
(561.8
|
)
|
1,067.9
|
1,628.4
|
(500.6
|
)
|
1,127.8
|
||||||||||||||||
Onshore Crude Oil Pipelines & Services:
|
||||||||||||||||||||||||
Customer relationship intangibles
|
10.7
|
(4.9
|
)
|
5.8
|
9.7
|
(4.1
|
)
|
5.6
|
||||||||||||||||
Contract-based intangibles
|
0.4
|
(0.3
|
)
|
0.1
|
0.4
|
(0.2
|
)
|
0.2
|
||||||||||||||||
Segment total
|
11.1
|
(5.2
|
)
|
5.9
|
10.1
|
(4.3
|
)
|
5.8
|
||||||||||||||||
Offshore Pipelines & Services:
|
||||||||||||||||||||||||
Customer relationship intangibles
|
203.9
|
(138.5
|
)
|
65.4
|
205.8
|
(129.2
|
)
|
76.6
|
||||||||||||||||
Contract-based intangibles
|
1.2
|
(0.4
|
)
|
0.8
|
1.2
|
(0.3
|
)
|
0.9
|
||||||||||||||||
Segment total
|
205.1
|
(138.9
|
)
|
66.2
|
207.0
|
(129.5
|
)
|
77.5
|
||||||||||||||||
Petrochemical & Refined Products Services:
|
||||||||||||||||||||||||
Customer relationship intangibles
|
104.3
|
(33.4
|
)
|
70.9
|
104.3
|
(28.4
|
)
|
75.9
|
||||||||||||||||
Contract-based intangibles
|
41.2
|
(5.9
|
)
|
35.3
|
57.6
|
(29.7
|
)
|
27.9
|
||||||||||||||||
Segment total
|
145.5
|
(39.3
|
)
|
106.2
|
161.9
|
(58.1
|
)
|
103.8
|
||||||||||||||||
Total all segments
|
$
|
2,616.8
|
$
|
(1,050.0
|
)
|
$
|
1,566.8
|
$
|
2,646.6
|
$
|
(990.4
|
)
|
$
|
1,656.2
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
NGL Pipelines & Services
|
$
|
39.7
|
$
|
41.1
|
$
|
40.1
|
||||||
Onshore Natural Gas Pipelines & Services
|
63.4
|
77.1
|
72.7
|
|||||||||
Onshore Crude Oil Pipelines & Services
|
0.9
|
0.4
|
0.4
|
|||||||||
Offshore Pipelines & Services
|
11.3
|
11.2
|
12.8
|
|||||||||
Petrochemical & Refined Products Services
|
10.4
|
17.2
|
11.6
|
|||||||||
Total
|
$
|
125.7
|
$
|
147.0
|
$
|
137.6
|
2013
|
2014
|
2015
|
2016
|
2017
|
||||||||||||||
$
|
107.9
|
$
|
96.2
|
$
|
90.3
|
$
|
92.1
|
$
|
96.0
|
§
|
State Line and Fairplay customer relationships – We acquired these customer relationships in connection with our acquisition of the State Line and Fairplay natural gas gathering systems in May 2010 (see Note 10). The carrying values of these intangible assets at December 31, 2012 are presented in the following table:
|
|
Gross
Value
|
Accumulated
Amortization
|
Carrying
Value
|
|||||||||
State Line natural gas gathering customer relationships (1)
|
$
|
675.0
|
$
|
(52.8
|
)
|
$
|
622.2
|
|||||
Fairplay natural gas gathering customer relationships (1)
|
116.6
|
(18.2
|
)
|
98.4
|
||||||||
Fairplay natural gas processing customer relationships (2)
|
103.4
|
(16.1
|
)
|
87.3
|
||||||||
Total acquired customer relationships
|
$
|
895.0
|
$
|
(87.1
|
)
|
$
|
807.9
|
|||||
|
||||||||||||
(1) These natural gas gathering customer relationship intangible assets are a component of our Onshore Natural Gas Pipelines & Services business segment.
(2) The Fairplay natural gas processing customer relationship intangible assets are a component of our NGL Pipelines & Services business segment.
|
§
|
San Juan Gathering System customer relationships – We acquired these customer relationships in connection with a merger transaction completed in September 2004. At December 31, 2012, the carrying value of this group of intangible assets was $173.4 million. These intangible assets are being amortized to earnings over their estimated economic life of 35 years through 2039. Amortization expense attributable to these customer relationships is recorded using a method that closely resembles the pattern in which the
|
economic benefits of the underlying natural gas resource basins are expected to be consumed or otherwise used.
|
§
|
Offshore Pipeline & Platform customer relationships – We acquired these customer relationships in connection with a merger transaction completed in September 2004. At December 31, 2012, the carrying value of this group of intangible assets was $65.4 million. These intangible assets are being amortized to earnings over their estimated economic lives, which range from 11 to 33 years (i.e., through 2015 to 2037). Amortization expense attributable to these customer relationships is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying crude oil and natural gas resource basins are expected to be consumed or otherwise used.
|
§
|
Encinal natural gas processing customer relationship – We acquired this customer relationship in connection with our acquisition of certain South Texas assets in 2006. At December 31, 2012, the carrying value of this intangible asset was $64.1 million. This intangible asset is being amortized to earnings over its estimated economic life of 20 years through 2026. Amortization expense attributable to this customer relationships is recorded using a method that closely resembles the pattern in which the economic benefit of the underlying natural gas resource basins are expected to be consumed or otherwise used.
|
§
|
Jonah natural gas gathering agreements – These intangible assets represent the value attributed to certain natural gas gathering contracts on the Jonah Gathering System that were acquired by TEPPCO in 2001. At December 31, 2012, the carrying value of this group of intangible assets was $96.1 million. These intangible assets are being amortized to earnings over their estimated economic life of 40 years through 2041. Amortization expense attributable to these intangible assets is recorded using a units-of-production method based on gathering volumes.
|
§
|
Shell Processing Agreement – This margin-band/keepwhole natural gas processing agreement grants us the right to process Shell Oil Company's (or its assignee's) current and future natural gas production from the state and federal waters of the Gulf of Mexico. We acquired the Shell Processing Agreement in connection with our purchase of certain U.S. Gulf Coast midstream energy assets from Shell Oil Company in 1999. At December 31, 2012, the carrying value of this intangible asset was $72.7 million. This intangible asset is being amortized to earnings on a straight-line basis over its estimated economic life of 20 years through 2019.
|
§
|
San Juan basin natural gas gathering agreements – These intangible assets represent the value attributed to certain natural gas gathering contracts with producers in the San Juan basin that were acquired by TEPPCO in 2002. At December 31, 2012, the carrying value of these intangible assets was $56.7 million. These intangible assets are being amortized to earnings over their estimated economic life of 20 years through 2022. Amortization expense attributable to these intangible assets is recorded using a units-of-production method based on gathering volumes.
|
|
NGL
Pipelines
& Services
|
Onshore
Natural Gas
Pipelines
& Services
|
Onshore
Crude Oil
Pipelines
& Services
|
Offshore
Pipelines
& Services
|
Petrochemical
& Refined
Products
Services
|
Consolidated
Total
|
||||||||||||||||||
Balance at January 1, 2010 (1)
|
$
|
341.2
|
$
|
284.9
|
$
|
303.0
|
$
|
82.1
|
$
|
1,007.1
|
$
|
2,018.3
|
||||||||||||
Goodwill related to acquisitions (2)
|
--
|
26.2
|
8.2
|
--
|
55.0
|
89.4
|
||||||||||||||||||
Balance at December 31, 2010
|
341.2
|
311.1
|
311.2
|
82.1
|
1,062.1
|
2,107.7
|
||||||||||||||||||
Goodwill adjustment (3)
|
--
|
--
|
--
|
--
|
(0.6
|
)
|
(0.6
|
)
|
||||||||||||||||
Goodwill related to the sale of assets (4)
|
--
|
(14.8
|
)
|
--
|
--
|
--
|
(14.8
|
)
|
||||||||||||||||
Balance at December 31, 2011
|
341.2
|
296.3
|
311.2
|
82.1
|
1,061.5
|
2,092.3
|
||||||||||||||||||
Reclassification to assets held for sale
|
--
|
--
|
--
|
--
|
(5.5
|
)
|
(5.5
|
)
|
||||||||||||||||
Balance at December 31, 2012
|
$
|
341.2
|
$
|
296.3
|
$
|
311.2
|
$
|
82.1
|
$
|
1,056.0
|
$
|
2,086.8
|
||||||||||||
|
||||||||||||||||||||||||
(1) The total carrying amount of goodwill at January 1, 2010 is net of $1.3 million of accumulated impairment charges incurred prior to 2010. No goodwill impairment charges were recorded during the three years ended December 31, 2012.
(2) Amount presented for Petrochemical & Refined Products Services includes $5.5 million of goodwill that was part of the drop down of trucking assets from EPCO (see Note 15).
(3) The goodwill we recorded in connection with a marine business acquisition completed in November 2010 was subsequently reduced in May 2011 due to a purchase price adjustment.
(4) In December 2011, we disposed of our ownership interests in Crystal (see Note 8), including related goodwill.
|
Goodwill related to acquisition of:
|
||||
State Line and Fairplay Natural Gas Gathering Systems
|
$
|
26.2
|
||
Marine shipyard business
|
49.5
|
|||
Drop-down of trucking assets from EPCO (see Note 15)
|
5.5 | |||
Other
|
8.2
|
|||
Total (1)
|
$
|
89.4
|
||
|
||||
(1) We attribute these goodwill amounts to our ability to leverage the acquired businesses with our existing asset base to create future business opportunities.
|
|
December 31,
|
|||||||
|
2012
|
2011
|
||||||
EPO senior debt obligations:
|
||||||||
Commercial Paper Notes, fixed-rates ranging from 0.30% to 0.50%, due January 2013
|
$
|
346.6
|
$
|
--
|
||||
Senior Notes S, 7.625% fixed-rate, due February 2012
|
--
|
490.5
|
||||||
Senior Notes P, 4.60% fixed-rate, due August 2012
|
--
|
500.0
|
||||||
Senior Notes C, 6.375% fixed-rate, due February 2013
|
350.0
|
350.0
|
||||||
Senior Notes T, 6.125% fixed-rate, due February 2013
|
182.5
|
182.5
|
||||||
Senior Notes M, 5.65% fixed-rate, due April 2013
|
400.0
|
400.0
|
||||||
Senior Notes U, 5.90% fixed-rate, due April 2013
|
237.6
|
237.6
|
||||||
Senior Notes O, 9.75% fixed-rate, due January 2014
|
500.0
|
500.0
|
||||||
Senior Notes G, 5.60% fixed-rate, due October 2014
|
650.0
|
650.0
|
||||||
Senior Notes I, 5.00% fixed-rate, due March 2015
|
250.0
|
250.0
|
||||||
Senior Notes X, 3.70% fixed-rate, due June 2015
|
400.0
|
400.0
|
||||||
Senior Notes FF, 1.25% fixed-rate, due August 2015
|
650.0
|
--
|
||||||
Senior Notes AA, 3.20% fixed-rate, due February 2016
|
750.0
|
750.0
|
||||||
$3.5 Billion Multi-Year Revolving Credit Facility, variable-rate, due September 2016
|
--
|
150.0
|
||||||
Senior Notes L, 6.30% fixed-rate, due September 2017
|
800.0
|
800.0
|
||||||
Senior Notes V, 6.65% fixed-rate, due April 2018
|
349.7
|
349.7
|
||||||
Senior Notes N, 6.50% fixed-rate, due January 2019
|
700.0
|
700.0
|
||||||
Senior Notes Q, 5.25% fixed-rate, due January 2020
|
500.0
|
500.0
|
||||||
Senior Notes Y, 5.20% fixed-rate, due September 2020
|
1,000.0
|
1,000.0
|
||||||
Senior Notes CC, 4.05% fixed-rate, due February 2022
|
650.0
|
650.0
|
||||||
Senior Notes 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
|
--
|
||||||
Senior Notes GG, 4.45% fixed-rate, due February 2043
|
1,100.0
|
--
|
||||||
TEPPCO senior debt obligations:
|
||||||||
TEPPCO Senior Notes, 7.625% fixed-rate, due February 2012
|
--
|
9.5
|
||||||
TEPPCO Senior Notes, 6.125% fixed-rate, due February 2013
|
17.5
|
17.5
|
||||||
TEPPCO Senior Notes, 5.90% fixed-rate, due April 2013
|
12.4
|
12.4
|
||||||
TEPPCO Senior Notes, 6.65% fixed-rate, due April 2018
|
0.3
|
0.3
|
||||||
TEPPCO Senior Notes, 7.55% fixed-rate, due April 2038
|
0.4
|
0.4
|
||||||
Total principal amount of senior debt obligations
|
14,646.6
|
12,950.0
|
||||||
EPO Junior Subordinated Notes A, fixed/variable-rate, due August 2066
|
550.0
|
550.0
|
||||||
EPO Junior Subordinated Notes C, fixed/variable-rate, due June 2067
|
285.8
|
285.8
|
||||||
EPO Junior Subordinated Notes B, fixed/variable-rate, due January 2068
|
682.7
|
682.7
|
||||||
TEPPCO Junior Subordinated Notes, fixed/variable-rate, due June 2067
|
14.2
|
14.2
|
||||||
Total principal amount of senior and junior debt obligations
|
16,179.3
|
14,482.7
|
||||||
Other, non-principal amounts:
|
||||||||
Change in fair value of debt hedged in fair value hedging relationship (1)
|
39.3
|
73.8
|
||||||
Unamortized discounts, net of premiums
|
(38.0
|
)
|
(30.0
|
)
|
||||
Other
|
21.2
|
2.9
|
||||||
Total other, non-principal amounts
|
22.5
|
46.7
|
||||||
Less current maturities of debt (2)
|
(1,546.6
|
)
|
(500.0
|
)
|
||||
Total long-term debt
|
$
|
14,655.2
|
$
|
14,029.4
|
||||
|
||||||||
(1) See Note 6 for information regarding our interest rate hedging activities.
(2) We expect to refinance the current maturities of our debt obligations at or prior to their maturity.
|
|
Scheduled Maturities of Debt
|
|||||||||||||||||||||||||||
|
Total
|
2013
|
2014
|
2015
|
2016
|
2017
|
After
2017
|
|||||||||||||||||||||
Commercial Paper Notes
|
$
|
346.6
|
$
|
346.6
|
$
|
--
|
$
|
--
|
$
|
--
|
$
|
--
|
$
|
--
|
||||||||||||||
Senior Notes
|
14,300.0
|
1,200.0
|
1,150.0
|
1,300.0
|
750.0
|
800.0
|
9,100.0
|
|||||||||||||||||||||
Junior Subordinated Notes
|
1,532.7
|
--
|
--
|
--
|
--
|
--
|
1,532.7
|
|||||||||||||||||||||
Total
|
$
|
16,179.3
|
$
|
1,546.6
|
$
|
1,150.0
|
$
|
1,300.0
|
$
|
750.0
|
$
|
800.0
|
$
|
10,632.7
|
Series
|
Fixed Annual
Interest Rate
|
Variable Annual
Interest Rate
Thereafter
|
Junior Subordinated Notes A
|
8.375% through August 2016 (1)
|
3-month LIBOR rate + 3.708% (4)
|
Junior Subordinated Notes B
|
7.034% through January 2018 (2)
|
Greater of: (i) 3-month LIBOR rate + 2.68% or (ii) 7.034% (5)
|
Junior Subordinated Notes C
|
7.00% through June 2017 (3)
|
3-month LIBOR rate + 2.778% (6)
|
(1) Interest is payable semi-annually in arrears in February and August of each year, which commenced in February 2007.
(2) Interest is payable semi-annually in arrears in January and July of each year, which commenced in January 2008.
(3) Interest is payable semi-annually in arrears in June and December of each year, which commenced in December 2009.
(4) Interest is payable quarterly in arrears in February, May, August and November of each year commencing in November 2016.
(5) Interest is payable quarterly in arrears in January, April, July and October of each year commencing in April 2018.
(6) Interest is payable quarterly in arrears in March, June, September and December of each year commencing in June 2017.
|
|
Range of
Interest Rates
Paid
|
Weighted-Average
Interest Rate
Paid
|
EPO $3.5 Billion Multi-Year Revolving Credit Facility
|
1.51% to 3.63%
|
1.59%
|
|
Holdings
Units
|
|||
Balance, December 31, 2009
|
139,191,640
|
|||
Common units issued upon vesting of restricted units
|
3,424
|
|||
Balance, November 21, 2010
|
139,195,064
|
|
Common
Units
(Unrestricted)
|
Restricted
Common
Units
|
Total
Common
Units
|
|||||||||
Balance, December 31, 2009
|
603,202,828
|
2,720,882
|
605,923,710
|
|||||||||
Common units issued in connection with underwritten offerings
|
37,950,000
|
--
|
37,950,000
|
|||||||||
Common units issued in connection with the Holdings Merger
|
208,813,454
|
--
|
208,813,454
|
|||||||||
Common units cancelled in connection with the Holdings Merger
|
(21,563,177
|
)
|
--
|
(21,563,177
|
)
|
|||||||
Common units issued in connection with DRIP and EUPP
|
8,378,053
|
--
|
8,378,053
|
|||||||||
Common units issued in connection with acquisition of marine shipyard assets
|
2,329,639
|
--
|
2,329,639
|
|||||||||
Common units issued to EPCO in exchange for equity interest in trucking business
|
523,306
|
--
|
523,306
|
|||||||||
Common units issued in connection with the vesting of unit options
|
193,030
|
--
|
193,030
|
|||||||||
Common units issued in connection with the vesting of restricted common unit awards
|
383,628
|
(383,628
|
)
|
--
|
||||||||
Restricted common units issued
|
--
|
1,393,925
|
1,393,925
|
|||||||||
Forfeiture of restricted common units
|
--
|
(169,565
|
)
|
(169,565
|
)
|
|||||||
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards
|
(103,241
|
)
|
--
|
(103,241
|
)
|
|||||||
Other
|
12,438
|
--
|
12,438
|
|||||||||
Balance, December 31, 2010
|
840,119,958
|
3,561,614
|
843,681,572
|
|||||||||
Common units issued in connection with underwritten offering
|
10,350,000
|
--
|
10,350,000
|
|||||||||
Common units issued in connection with Duncan Merger
|
24,277,310
|
--
|
24,277,310
|
|||||||||
Common units issued in connection with DRIP and EUPP
|
2,337,904
|
--
|
2,337,904
|
|||||||||
Common units issued in connection with the vesting of restricted common unit awards
|
924,108
|
(924,108
|
)
|
--
|
||||||||
Restricted common units issued
|
--
|
1,414,630
|
1,414,630
|
|||||||||
Forfeiture of restricted common units
|
--
|
(183,920
|
)
|
(183,920
|
)
|
|||||||
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards
|
(255,276
|
)
|
--
|
(255,276
|
)
|
|||||||
Other
|
(1,802
|
)
|
--
|
(1,802
|
)
|
|||||||
Balance, December 31, 2011
|
877,752,202
|
3,868,216
|
881,620,418
|
|||||||||
Common units issued in connection with underwritten offering
|
9,200,000
|
--
|
9,200,000
|
|||||||||
Common units issued in connection with at-the-market program
|
3,978,545
|
--
|
3,978,545
|
|||||||||
Common units issued in connection with DRIP and EUPP
|
2,814,660
|
--
|
2,814,660
|
|||||||||
Common units issued in connection with the vesting of unit options
|
213,914
|
--
|
213,914
|
|||||||||
Common units issued in connection with the vesting of restricted common unit awards
|
1,316,603
|
(1,316,603
|
)
|
--
|
||||||||
Common units issued in connection with the vesting of other types of equity-based awards
|
52,168
|
--
|
52,168
|
|||||||||
Restricted common units issued
|
--
|
1,588,738
|
1,588,738
|
|||||||||
Forfeiture of restricted common unit awards
|
--
|
(246,865
|
)
|
(246,865
|
)
|
|||||||
Acquisition and cancellation of treasury units in connection with the vesting of equity-based awards
|
(408,241
|
)
|
--
|
(408,241
|
)
|
|||||||
Balance, December 31, 2012
|
894,919,851
|
3,893,486
|
898,813,337
|
§
|
We issued 13,225,000 common units to the public at an offering price of $41.25 per unit in December 2010, which generated total net cash proceeds of $528.5 million.
|
§
|
We issued 10,350,000 common units to the public at an offering price of $44.68 per unit in December 2011, which generated total net cash proceeds of $448.5 million. In addition, EPO utilized the 2010 Shelf to issue $2.75 billion of unsecured senior notes during 2011 (see Note 12).
|
§
|
We issued 9,200,000 common units to the public at an offering price of $53.07 per unit in September 2012, which generated total net cash proceeds of $473.3 million. In addition, EPO issued $2.5 billion of unsecured senior notes during 2012 using the 2010 Shelf (see Note 12).
|
|
December 31,
|
|||||||
|
2012
|
2011
|
||||||
Commodity derivative instruments (1)
|
$
|
10.1
|
$
|
(21.4
|
)
|
|||
Interest rate derivative instruments (1)
|
(383.0
|
)
|
(329.0
|
)
|
||||
Foreign currency translation adjustment (2)
|
1.7
|
1.7
|
||||||
Pension and postretirement benefit plans
|
0.8
|
(1.7
|
)
|
|||||
Other
|
--
|
(1.0
|
)
|
|||||
Total
|
$
|
(370.4
|
)
|
$
|
(351.4
|
)
|
||
|
||||||||
(1) See Note 6 for additional information regarding our derivative instruments.
(2) Relates to transactions of a Canadian subsidiary.
|
|
December 31,
|
|||||||
|
2012
|
2011
|
||||||
Joint venture partners (1)
|
$
|
108.3
|
$
|
105.9
|
||||
(1) Represents third party ownership interests in joint ventures that we consolidate, including Tri-States NGL Pipeline L.L.C., Independence Hub LLC, Rio Grande Pipeline Company and Wilprise Pipeline Company LLC.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Limited partners of Enterprise other than Holdings (prior to Holdings Merger)
|
$
|
--
|
$
|
--
|
$
|
1,000.3
|
||||||
Limited partners of Duncan Energy Partners other than EPO and its subsidiaries (prior to Duncan Merger)
|
--
|
20.9
|
37.1
|
|||||||||
Joint venture partners
|
8.1
|
20.5
|
25.5
|
|||||||||
Total
|
$
|
8.1
|
$
|
41.4
|
$
|
1,062.9
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Cash distributions paid to noncontrolling interests:
|
||||||||||||
Limited partners of Enterprise (prior to Holdings Merger)
|
$
|
--
|
$
|
--
|
$
|
1,395.1
|
||||||
Limited partners of Duncan Energy Partners other than EPO and its subsidiaries (prior to Duncan Merger)
|
--
|
32.9
|
42.9
|
|||||||||
Joint venture partners
|
13.3
|
27.8
|
29.8
|
|||||||||
Total
|
$
|
13.3
|
$
|
60.7
|
$
|
1,467.8
|
||||||
|
||||||||||||
Cash contributions from noncontrolling interests:
|
||||||||||||
Limited partners of Enterprise (prior to Holdings Merger)
|
$
|
--
|
$
|
--
|
$
|
1,092.0
|
||||||
Limited partners of Duncan Energy Partners other than EPO and its subsidiaries (prior to Duncan Merger)
|
--
|
2.6
|
1.7
|
|||||||||
Joint venture partners
|
6.6
|
5.9
|
2.8
|
|||||||||
Total
|
$
|
6.6
|
$
|
8.5
|
$
|
1,096.5
|
|
Distribution Per Common Unit
|
Record
Date
|
Payment
Date
|
|||
2011
|
|
|
||||
1st Quarter
|
$
|
0.5975
|
04/29/11
|
05/06/11
|
||
2nd Quarter
|
$
|
0.6050
|
07/29/11
|
08/10/11
|
||
3rd Quarter
|
$
|
0.6125
|
10/31/11
|
11/09/11
|
||
4th Quarter
|
$
|
0.6200
|
01/31/12
|
02/09/12
|
||
2012
|
|
|
||||
1st Quarter
|
$
|
0.6275
|
04/30/12
|
05/09/12
|
||
2nd Quarter
|
$
|
0.6350
|
07/31/12
|
08/08/12
|
||
3rd Quarter
|
$
|
0.6500
|
10/31/12
|
11/08/12
|
||
4th Quarter
|
$
|
0.6600
|
01/31/13
|
02/07/13
|
§
|
Our NGL Pipelines & Services business segment includes our natural gas processing plants and related NGL marketing activities; approximately 16,700 miles of NGL pipelines; NGL and related product storage facilities; and 14 NGL fractionators. This segment also includes our NGL import and export terminal operations.
|
§
|
Our Onshore Natural Gas Pipelines & Services business segment includes approximately 19,900 miles of onshore natural gas pipeline systems that provide for the gathering and transportation of natural gas in Colorado, Louisiana, New Mexico, Texas and Wyoming. We lease underground salt dome natural gas storage facilities located in Texas and Louisiana and own an underground salt dome storage cavern in Texas, all of which are important to our natural gas pipeline operations. This segment also includes our related natural gas marketing activities.
|
§
|
Our Onshore Crude Oil Pipelines & Services business segment includes approximately 5,100 miles of onshore crude oil pipelines, crude oil storage terminals located in Oklahoma and Texas, and our crude oil marketing activities.
|
§
|
Our Offshore Pipelines & Services business segment serves some of the most active drilling and development regions, including deepwater production fields, in the northern Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. This segment includes approximately 2,300 miles of offshore natural gas and crude oil pipelines and six offshore hub platforms.
|
§
|
Our Petrochemical & Refined Products Services business segment includes (i) propylene fractionation and related operations; (ii) a butane isomerization facility and related pipeline system; (iii) octane enhancement and high purity isobutylene production facilities; (iv) refined products pipelines and related marketing activities; and (v) marine transportation and other services.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Revenues
|
$
|
42,583.1
|
$
|
44,313.0
|
$
|
33,739.3
|
||||||
Less: Operating costs and expenses
|
(39,367.9
|
)
|
(41,318.5
|
)
|
(31,449.3
|
)
|
||||||
Add: Equity in income of unconsolidated affiliates
|
64.3
|
46.4
|
62.0
|
|||||||||
Depreciation, amortization and accretion recorded in operating costs and expenses
|
1,061.7
|
958.7
|
936.3
|
|||||||||
Non-cash asset impairment charges recorded in operating costs and expenses
|
63.4
|
27.8
|
8.4
|
|||||||||
Operating lease expenses paid by EPCO recorded in operating costs and expenses
|
--
|
0.3
|
0.7
|
|||||||||
Gains attributable to disposal of assets recorded in operating costs and expenses
|
(17.6
|
)
|
(156.0
|
)
|
(44.4
|
)
|
||||||
Total segment gross operating margin
|
$
|
4,387.0
|
$
|
3,871.7
|
$
|
3,253.0
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Total segment gross operating margin
|
$
|
4,387.0
|
$
|
3,871.7
|
$
|
3,253.0
|
||||||
Adjustments to reconcile total segment gross operating margin to operating income:
|
||||||||||||
Amounts included in operating costs and expenses:
|
||||||||||||
Depreciation, amortization and accretion
|
(1,061.7
|
)
|
(958.7
|
)
|
(936.3
|
)
|
||||||
Non-cash asset impairment charges
|
(63.4
|
)
|
(27.8
|
)
|
(8.4
|
)
|
||||||
Operating lease expenses paid by EPCO
|
--
|
(0.3
|
)
|
(0.7
|
)
|
|||||||
Gains attributable to disposal of assets
|
17.6
|
156.0
|
44.4
|
|||||||||
General and administrative costs
|
(170.3
|
)
|
(181.8
|
)
|
(204.8
|
)
|
||||||
Operating income
|
3,109.2
|
2,859.1
|
2,147.2
|
|||||||||
Other expense, net
|
(698.4
|
)
|
(743.6
|
)
|
(737.4
|
)
|
||||||
Income before income taxes
|
$
|
2,410.8
|
$
|
2,115.5
|
$
|
1,409.8
|
|
Reportable Business Segments
|
|||||||||||||||||||||||||||||||
|
NGL
Pipelines
& Services
|
Onshore
Natural Gas
Pipelines
& Services
|
Onshore
Crude Oil
Pipelines
& Services
|
Offshore
Pipelines
& Services
|
Petrochemical
& Refined
Products
Services
|
Other
Investments
|
Adjustments
and
Eliminations
|
Consolidated
Total
|
||||||||||||||||||||||||
Revenues from third parties:
|
||||||||||||||||||||||||||||||||
Year ended December 31, 2012
|
$
|
15,158.9
|
$
|
3,297.7
|
$
|
17,661.6
|
$
|
182.7
|
$
|
6,208.9
|
$
|
--
|
$
|
--
|
$
|
42,509.8
|
||||||||||||||||
Year ended December 31, 2011
|
16,938.1
|
3,510.0
|
16,061.0
|
246.4
|
6,782.4
|
--
|
--
|
43,537.9
|
||||||||||||||||||||||||
Year ended December 31, 2010
|
13,736.8
|
3,479.4
|
10,794.7
|
300.3
|
4,729.7
|
--
|
--
|
33,040.9
|
||||||||||||||||||||||||
Revenues from related parties:
|
||||||||||||||||||||||||||||||||
Year ended December 31, 2012
|
9.5
|
54.9
|
0.1
|
8.8
|
--
|
--
|
--
|
73.3
|
||||||||||||||||||||||||
Year ended December 31, 2011
|
545.2
|
220.2
|
0.1
|
9.6
|
--
|
--
|
--
|
775.1
|
||||||||||||||||||||||||
Year ended December 31, 2010
|
465.7
|
222.2
|
0.1
|
10.4
|
--
|
--
|
--
|
698.4
|
||||||||||||||||||||||||
Intersegment and intrasegment
revenues:
|
||||||||||||||||||||||||||||||||
Year ended December 31, 2012
|
12,500.6
|
871.6
|
6,906.9
|
10.4
|
1,758.9
|
--
|
(22,048.4
|
)
|
--
|
|||||||||||||||||||||||
Year ended December 31, 2011
|
13,657.7
|
1,131.8
|
4,904.3
|
6.6
|
1,799.1
|
--
|
(21,499.5
|
)
|
--
|
|||||||||||||||||||||||
Year ended December 31, 2010
|
10,209.9
|
900.8
|
927.0
|
3.6
|
1,106.7
|
--
|
(13,148.0
|
)
|
--
|
|||||||||||||||||||||||
Total revenues:
|
||||||||||||||||||||||||||||||||
Year ended December 31, 2012
|
27,669.0
|
4,224.2
|
24,568.6
|
201.9
|
7,967.8
|
--
|
(22,048.4
|
)
|
42,583.1
|
|||||||||||||||||||||||
Year ended December 31, 2011
|
31,141.0
|
4,862.0
|
20,965.4
|
262.6
|
8,581.5
|
--
|
(21,499.5
|
)
|
44,313.0
|
|||||||||||||||||||||||
Year ended December 31, 2010
|
24,412.4
|
4,602.4
|
11,721.8
|
314.3
|
5,836.4
|
--
|
(13,148.0
|
)
|
33,739.3
|
|||||||||||||||||||||||
Equity in income (loss) of
unconsolidated affiliates:
|
||||||||||||||||||||||||||||||||
Year ended December 31, 2012
|
15.9
|
4.4
|
32.6
|
26.9
|
(17.9
|
)
|
2.4
|
--
|
64.3
|
|||||||||||||||||||||||
Year ended December 31, 2011
|
21.8
|
5.5
|
(4.1
|
)
|
27.1
|
(18.7
|
)
|
14.8
|
--
|
46.4
|
||||||||||||||||||||||
Year ended December 31, 2010
|
17.7
|
4.6
|
6.7
|
44.8
|
(9.0
|
)
|
(2.8
|
)
|
--
|
62.0
|
||||||||||||||||||||||
Gross operating margin:
|
||||||||||||||||||||||||||||||||
Year ended December 31, 2012
|
2,468.5
|
775.5
|
387.7
|
173.0
|
579.9
|
2.4
|
--
|
4,387.0
|
||||||||||||||||||||||||
Year ended December 31, 2011
|
2,184.2
|
675.3
|
234.0
|
228.2
|
535.2
|
14.8
|
--
|
3,871.7
|
||||||||||||||||||||||||
Year ended December 31, 2010
|
1,732.6
|
527.2
|
113.7
|
297.8
|
584.5
|
(2.8
|
)
|
--
|
3,253.0
|
|||||||||||||||||||||||
Property, plant and equipment, net:
(see Note 8)
|
||||||||||||||||||||||||||||||||
At December 31, 2012
|
8,494.8
|
8,950.1
|
1,385.9
|
1,343.0
|
2,559.5
|
--
|
2,113.1
|
24,846.4
|
||||||||||||||||||||||||
At December 31, 2011
|
7,137.8
|
8,495.4
|
456.9
|
1,416.4
|
2,539.5
|
--
|
2,145.6
|
22,191.6
|
||||||||||||||||||||||||
At December 31, 2010
|
6,813.1
|
6,595.0
|
427.9
|
1,390.9
|
2,498.8
|
--
|
1,607.2
|
19,332.9
|
||||||||||||||||||||||||
Investments in unconsolidated
affiliates: (see Note 9)
|
||||||||||||||||||||||||||||||||
At December 31, 2012
|
324.6
|
24.9
|
493.8
|
479.0
|
72.3
|
--
|
--
|
1,394.6
|
||||||||||||||||||||||||
At December 31, 2011
|
146.1
|
30.1
|
170.7
|
424.9
|
64.7
|
1,023.1
|
--
|
1,859.6
|
||||||||||||||||||||||||
At December 31, 2010
|
131.5
|
32.6
|
172.2
|
443.2
|
76.8
|
1,436.8
|
--
|
2,293.1
|
||||||||||||||||||||||||
Intangible assets, net: (see Note 11)
|
||||||||||||||||||||||||||||||||
At December 31, 2012
|
320.6
|
1,067.9
|
5.9
|
66.2
|
106.2
|
--
|
--
|
1,566.8
|
||||||||||||||||||||||||
At December 31, 2011
|
341.3
|
1,127.8
|
5.8
|
77.5
|
103.8
|
--
|
--
|
1,656.2
|
||||||||||||||||||||||||
At December 31, 2010
|
379.7
|
1,246.1
|
6.2
|
88.7
|
121.0
|
--
|
--
|
1,841.7
|
||||||||||||||||||||||||
Goodwill: (see Note 11)
|
||||||||||||||||||||||||||||||||
At December 31, 2012
|
341.2
|
296.3
|
311.2
|
82.1
|
1,056.0
|
--
|
--
|
2,086.8
|
||||||||||||||||||||||||
At December 31, 2011
|
341.2
|
296.3
|
311.2
|
82.1
|
1,061.5
|
--
|
--
|
2,092.3
|
||||||||||||||||||||||||
At December 31, 2010
|
341.2
|
311.1
|
311.2
|
82.1
|
1,062.1
|
--
|
--
|
2,107.7
|
||||||||||||||||||||||||
Segment assets:
|
||||||||||||||||||||||||||||||||
At December 31, 2012
|
9,481.2
|
10,339.2
|
2,196.8
|
1,970.3
|
3,794.0
|
--
|
2,113.1
|
29,894.6
|
||||||||||||||||||||||||
At December 31, 2011
|
7,966.4
|
9,949.6
|
944.6
|
2,000.9
|
3,769.5
|
1,023.1
|
2,145.6
|
27,799.7
|
||||||||||||||||||||||||
At December 31, 2010
|
7,665.5
|
8,184.8
|
917.5
|
2,004.9
|
3,758.7
|
1,436.8
|
1,607.2
|
25,575.4
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
NGL Pipelines & Services:
|
||||||||||||
Sales of NGLs and related products
|
$
|
14,218.5
|
$
|
16,724.6
|
$
|
13,449.4
|
||||||
Midstream services
|
949.9
|
758.7
|
753.1
|
|||||||||
Total
|
15,168.4
|
17,483.3
|
14,202.5
|
|||||||||
Onshore Natural Gas Pipelines & Services:
|
||||||||||||
Sales of natural gas
|
2,395.4
|
2,866.5
|
2,928.7
|
|||||||||
Midstream services
|
957.2
|
863.7
|
772.9
|
|||||||||
Total
|
3,352.6
|
3,730.2
|
3,701.6
|
|||||||||
Onshore Crude Oil Pipelines & Services:
|
||||||||||||
Sales of crude oil
|
17,548.7
|
15,962.6
|
10,710.4
|
|||||||||
Midstream services
|
113.0
|
98.5
|
84.4
|
|||||||||
Total
|
17,661.7
|
16,061.1
|
10,794.8
|
|||||||||
Offshore Pipelines & Services:
|
||||||||||||
Sales of natural gas
|
0.4
|
1.1
|
1.3
|
|||||||||
Sales of crude oil
|
3.3
|
9.4
|
9.5
|
|||||||||
Midstream services
|
187.8
|
245.5
|
299.9
|
|||||||||
Total
|
191.5
|
256.0
|
310.7
|
|||||||||
Petrochemical & Refined Products Services:
|
||||||||||||
Sales of petrochemicals and refined products
|
5,470.9
|
6,000.6
|
4,009.1
|
|||||||||
Midstream services
|
738.0
|
781.8
|
720.6
|
|||||||||
Total
|
6,208.9
|
6,782.4
|
4,729.7
|
|||||||||
Total consolidated revenues
|
$
|
42,583.1
|
$
|
44,313.0
|
$
|
33,739.3
|
||||||
|
||||||||||||
Consolidated costs and expenses
|
||||||||||||
Operating costs and expenses:
|
||||||||||||
Cost of sales
|
$
|
36,015.5
|
$
|
38,292.6
|
$
|
28,723.1
|
||||||
Other operating costs and expenses (1)
|
2,244.9
|
2,195.4
|
1,825.9
|
|||||||||
Depreciation, amortization and accretion
|
1,061.7
|
958.7
|
936.3
|
|||||||||
Gains attributable to disposal of assets
|
(17.6
|
)
|
(156.0
|
)
|
(44.4
|
)
|
||||||
Non-cash asset impairment charges
|
63.4
|
27.8
|
8.4
|
|||||||||
General and administrative costs
|
170.3
|
181.8
|
204.8
|
|||||||||
Total consolidated costs and expenses
|
$
|
39,538.2
|
$
|
41,500.3
|
$
|
31,654.1
|
||||||
|
||||||||||||
(1) Represents cost of operating our plants, pipelines and other fixed assets, excluding non-cash depreciation, amortization and accretion charges.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Revenues – related parties:
|
||||||||||||
Energy Transfer Equity and subsidiaries
|
$
|
--
|
$
|
573.2
|
$
|
490.5
|
||||||
Other unconsolidated affiliates
|
73.3
|
201.9
|
207.9
|
|||||||||
Total revenue – related parties
|
$
|
73.3
|
$
|
775.1
|
$
|
698.4
|
||||||
Costs and expenses – related parties:
|
||||||||||||
EPCO and affiliates
|
$
|
816.9
|
$
|
722.7
|
$
|
712.5
|
||||||
Energy Transfer Equity and subsidiaries
|
--
|
1,101.5
|
724.4
|
|||||||||
Other unconsolidated affiliates
|
40.2
|
49.8
|
50.2
|
|||||||||
Total costs and expenses – related parties
|
$
|
857.1
|
$
|
1,874.0
|
$
|
1,487.1
|
|
December 31,
|
|||||||
|
2012
|
2011
|
||||||
Accounts receivable - related parties:
|
||||||||
Energy Transfer Equity and subsidiaries
|
$
|
--
|
$
|
28.4
|
||||
Other unconsolidated affiliates
|
2.5
|
15.1
|
||||||
Total accounts receivable – related parties
|
$
|
2.5
|
$
|
43.5
|
||||
|
||||||||
Accounts payable - related parties:
|
||||||||
EPCO and affiliates
|
$
|
102.4
|
$
|
108.3
|
||||
Energy Transfer Equity and subsidiaries
|
--
|
92.6
|
||||||
Other unconsolidated affiliates
|
24.7
|
10.7
|
||||||
Total accounts payable – related parties
|
$
|
127.1
|
$
|
211.6
|
Number of Units
|
Percentage of
Total Units
Outstanding
|
339,130,881 (1)
|
37.5%
|
(1) Includes 4,520,431 Class B units.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Enterprise
|
$
|
750.2
|
$
|
701.5
|
$
|
344.1
|
||||||
Holdings (prior to Holdings Merger)
|
--
|
--
|
237.4
|
|||||||||
Total
|
$
|
750.2
|
$
|
701.5
|
$
|
581.5
|
§
|
EPCO will provide selling, general and administrative services and management and operating services as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel.
|
§
|
We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time with respect to the services provided to us by EPCO.
|
§
|
EPCO will allow us to participate as a named insured in its overall insurance program, with the associated premiums and other costs being allocated to us. See Note 19 for additional information regarding our insurance programs.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Operating costs and expenses
|
$
|
719.4
|
$
|
611.6
|
$
|
588.5
|
||||||
General and administrative expenses
|
97.5
|
111.1
|
124.0
|
|||||||||
Total costs and expenses
|
$
|
816.9
|
$
|
722.7
|
$
|
712.5
|
§
|
We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $7.8 million, $18.3 million and $13.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Expenses with Promix were $27.4 million, $44.9 million and $35.6 million for the years ended December 31, 2012, 2011 and 2010, respectively.
|
§
|
For the years ended December 31, 2011 and 2010, we paid $2.8 million and $8.9 million, respectively, to Centennial for other pipeline transportation services. No payments were made in 2012.
|
§
|
For the years ended December 31, 2012, 2011 and 2010, we paid Seaway $18.1 million, $1.4 million and $4.5 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities.
|
§
|
For the year ended December 31, 2012, 2011 and 2010, we paid White River Hub $6.6 million, $6.7 million and $6.0 million, respectively, for pipeline transportation services.
|
§
|
We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $19.4 million, $13.0 million and $11.5 million for the years ended December 31, 2012, 2011 and 2010, respectively.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Current:
|
||||||||||||
Federal
|
$
|
18.9
|
$
|
(4.0
|
)
|
$
|
2.2
|
|||||
State
|
28.9
|
18.9
|
16.0
|
|||||||||
Foreign
|
1.2
|
0.2
|
--
|
|||||||||
Total current
|
49.0
|
15.1
|
18.2
|
|||||||||
Deferred:
|
||||||||||||
Federal
|
(64.7
|
)
|
11.5
|
5.3
|
||||||||
State
|
(1.4
|
)
|
0.8
|
2.9
|
||||||||
Foreign
|
(0.1
|
)
|
(0.2
|
)
|
(0.3
|
)
|
||||||
Total deferred
|
(66.2
|
)
|
12.1
|
7.9
|
||||||||
Total provision for (benefit from) income taxes
|
$
|
(17.2
|
)
|
$
|
27.2
|
$
|
26.1
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Pre-Tax Net Book Income ("NBI")
|
$
|
2,410.8
|
$
|
2,115.5
|
$
|
1,409.8
|
||||||
|
||||||||||||
Texas Margin Tax (1)
|
$
|
23.5
|
$
|
19.1
|
$
|
18.3
|
||||||
State income taxes (net of federal benefit)
|
5.3
|
0.5
|
0.4
|
|||||||||
Federal income taxes computed by applying the federal
statutory rate to NBI of corporate entities
|
(1.6
|
)
|
5.0
|
8.0
|
||||||||
Valuation allowance
|
(2.0
|
)
|
(0.2
|
)
|
--
|
|||||||
Expiration of tax net operating loss
|
2.4
|
0.2
|
--
|
|||||||||
Tax gain on conversion of corporate subsidiaries
into limited liability companies
|
(45.3
|
)
|
--
|
--
|
||||||||
Other permanent differences
|
0.5
|
2.6
|
(0.6
|
)
|
||||||||
Provision for (benefit from) income taxes
|
$
|
(17.2
|
)
|
$
|
27.2
|
$
|
26.1
|
|||||
|
||||||||||||
Effective income tax rate
|
(0.7
|
)%
|
1.3
|
%
|
1.9
|
%
|
||||||
|
||||||||||||
(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.
|
|
At December 31,
|
|||||||
|
2012
|
2011
|
||||||
Deferred tax assets:
|
||||||||
Net operating loss carryovers (1)
|
$
|
0.2
|
$
|
17.8
|
||||
Employee benefit plans
|
0.1
|
3.0
|
||||||
Deferred revenue
|
--
|
1.5
|
||||||
Equity investment in partnerships
|
--
|
0.9
|
||||||
AROs
|
--
|
0.1
|
||||||
Accruals
|
1.5
|
1.6
|
||||||
Total deferred tax assets
|
1.8
|
24.9
|
||||||
Valuation allowance (2)
|
--
|
2.0
|
||||||
Net deferred tax assets
|
1.8
|
22.9
|
||||||
Less: Deferred tax liabilities:
|
||||||||
Property, plant and equipment
|
23.7
|
112.1
|
||||||
Equity investment in partnerships
|
0.6 | -- | ||||||
Total deferred tax liabilities
|
24.3
|
112.1
|
||||||
Total net deferred tax liabilities
|
$
|
22.5
|
$
|
89.2
|
||||
|
||||||||
Current portion of total net deferred tax assets
|
$
|
--
|
$
|
2.0
|
||||
Long-term portion of total net deferred tax liabilities
|
$
|
22.5
|
$
|
91.2
|
||||
|
||||||||
(1) These losses expire in various years between 2013 and 2028 and are subject to limitations on their utilization.
(2) We record a valuation allowance to reduce our deferred tax assets to the amount of future benefit that is more likely than not to be realized.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
BASIC EARNINGS PER UNIT
|
||||||||||||
Numerator:
|
||||||||||||
Net income attributable to limited partners
|
$
|
2,419.9
|
$
|
2,046.9
|
$
|
320.8
|
||||||
Denominator:
|
||||||||||||
Weighted-average number of distribution-bearing
|
||||||||||||
common units outstanding
|
861.8
|
824.6
|
274.5
|
|||||||||
Basic earnings per unit:
|
||||||||||||
Net income attributable to limited partners
|
$
|
2.81
|
$
|
2.48
|
$
|
1.17
|
||||||
DILUTED EARNINGS PER UNIT
|
||||||||||||
Numerator:
|
||||||||||||
Net income attributable to limited partners
|
$
|
2,419.9
|
$
|
2,046.9
|
$
|
320.8
|
||||||
Denominator:
|
||||||||||||
Weighted-average number of units outstanding:
|
||||||||||||
Distribution-bearing common units
|
861.8
|
824.6
|
274.5
|
|||||||||
Class B units
|
4.5
|
4.5
|
0.5
|
|||||||||
Designated Units
|
25.5
|
29.5
|
3.4
|
|||||||||
Incremental option units
|
1.4
|
1.3
|
0.1
|
|||||||||
Total
|
893.2
|
859.9
|
278.5
|
|||||||||
Diluted earnings per unit:
|
||||||||||||
Net income attributable to limited partners
|
$
|
2.71
|
$
|
2.38
|
$
|
1.15
|
|
Payment or Settlement due by Period
|
|||||||||||||||||||||||||||
Contractual Obligations
|
Total
|
2013
|
2014
|
2015
|
2016
|
2017
|
Thereafter
|
|||||||||||||||||||||
Scheduled maturities of debt obligations
|
$
|
16,179.3
|
$
|
1,546.6
|
$
|
1,150.0
|
$
|
1,300.0
|
$
|
750.0
|
$
|
800.0
|
$
|
10,632.7
|
||||||||||||||
Estimated cash interest payments
|
$
|
17,072.7
|
$
|
840.4
|
$
|
765.2
|
$
|
706.2
|
$
|
682.3
|
$
|
668.1
|
$
|
13,410.5
|
||||||||||||||
Operating lease obligations
|
$
|
363.0
|
$
|
51.3
|
$
|
44.1
|
$
|
42.8
|
$
|
37.5
|
$
|
33.3
|
$
|
154.0
|
||||||||||||||
Purchase obligations:
|
||||||||||||||||||||||||||||
Product purchase commitments:
|
||||||||||||||||||||||||||||
Estimated payment obligations:
|
||||||||||||||||||||||||||||
Natural gas
|
$
|
4,027.2
|
$
|
911.8
|
$
|
733.4
|
$
|
667.2
|
$
|
614.2
|
$
|
338.7
|
$
|
761.9
|
||||||||||||||
NGLs
|
$
|
1,704.8
|
$
|
1,136.3
|
$
|
447.1
|
$
|
121.4
|
$
|
--
|
$
|
--
|
$
|
--
|
||||||||||||||
Crude oil
|
$
|
386.1
|
$
|
386.1
|
$
|
--
|
$
|
--
|
$
|
--
|
$
|
--
|
$
|
--
|
||||||||||||||
Petrochemicals & refined products
|
$
|
2,121.8
|
$
|
1,519.7
|
$
|
366.0
|
$
|
119.1
|
$
|
117.0
|
$
|
--
|
$
|
--
|
||||||||||||||
Other
|
$
|
127.7
|
$
|
83.9
|
$
|
7.6
|
$
|
7.2
|
$
|
6.9
|
$
|
6.3
|
$
|
15.8
|
||||||||||||||
Underlying major volume commitments:
|
||||||||||||||||||||||||||||
Natural gas (in TBtus)
|
1,442
|
321
|
260
|
237
|
220
|
128
|
276
|
|||||||||||||||||||||
NGLs (in MMBbls)
|
44
|
27
|
13
|
4
|
--
|
--
|
--
|
|||||||||||||||||||||
Crude oil (in MMBbls)
|
5
|
5
|
--
|
--
|
--
|
--
|
--
|
|||||||||||||||||||||
Petrochemicals & refined products (in MMBbls)
|
29
|
20
|
5
|
2
|
2
|
-- | -- | |||||||||||||||||||||
Service payment commitments
|
$
|
745.5
|
$
|
114.5
|
$
|
97.2
|
$
|
98.7 |
$
|
91.9
|
$
|
86.1
|
$
|
257.1
|
||||||||||||||
Capital expenditure commitments
|
$
|
1,754.0
|
$
|
1,754.0
|
$
|
--
|
$
|
--
|
$
|
--
|
$
|
--
|
$
|
--
|
§
|
We have long and short-term product purchase obligations for natural gas, NGLs, crude oil, refined products and certain petrochemicals with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods presented. Our estimated future payment obligations are based on the contractual price in each agreement at December 31, 2012 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. At December 31, 2012, we did not have any significant product purchase commitments with fixed or minimum pricing provisions with remaining terms in excess of one year.
|
§
|
We have long and short-term commitments to pay service providers. Our contractual service payment commitments primarily represent our obligations under firm pipeline transportation contracts. Payment obligations vary by contract, but generally represent a price per unit of volume multiplied by a firm transportation volume commitment.
|
§
|
We have short-term payment obligations relating to our capital spending program, including our share of the capital spending of our unconsolidated affiliates. These commitments represent unconditional payment obligations for services to be rendered or products to be delivered in connection with capital projects.
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Decrease (increase) in:
|
||||||||||||
Accounts receivable – trade
|
$
|
161.5
|
$
|
(709.0
|
)
|
$
|
(683.7
|
)
|
||||
Accounts receivable – related parties
|
35.3
|
(7.0
|
)
|
2.9
|
||||||||
Inventories
|
(227.8
|
)
|
135.8
|
(437.5
|
)
|
|||||||
Prepaid and other current assets
|
(12.6
|
)
|
(27.7
|
)
|
(87.4
|
)
|
||||||
Other assets
|
(39.6
|
)
|
3.9
|
14.7
|
||||||||
Increase (decrease) in:
|
||||||||||||
Accounts payable – trade
|
34.1
|
44.2
|
104.7
|
|||||||||
Accounts payable – related parties
|
(84.3
|
)
|
78.4
|
46.0
|
||||||||
Accrued product payables
|
(422.5
|
)
|
726.2
|
772.6
|
||||||||
Accrued interest
|
12.7
|
35.2
|
25.1
|
|||||||||
Other current liabilities
|
(14.4
|
)
|
(23.2
|
)
|
52.9
|
|||||||
Other liabilities
|
(24.9
|
)
|
10.1
|
(0.7
|
)
|
|||||||
Net effect of changes in operating accounts
|
$
|
(582.5
|
)
|
$
|
266.9
|
$
|
(190.4
|
)
|
||||
|
||||||||||||
Cash payments for interest, net of $116.8, $106.7 and $47.2 capitalized in 2012, 2011 and 2010, respectively
|
$
|
757.3
|
$
|
711.4
|
$
|
724.1
|
||||||
|
||||||||||||
Cash payments for federal and state income taxes
|
$
|
44.8
|
$
|
13.4
|
$
|
15.6
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Sale of Energy Transfer Equity common units (see Note 9)
|
$
|
1,095.3
|
$
|
375.2
|
$
|
--
|
||||||
Sale of ownership interests in Crystal (see Note 8)
|
--
|
547.8
|
--
|
|||||||||
Sale of marine transportation assets (see Note 8)
|
--
|
53.2
|
--
|
|||||||||
Insurance recoveries attributable to West Storage claims (see Note 19)
|
30.0
|
20.0
|
--
|
|||||||||
Insurance settlement attributable to disposal of certain offshore assets (see Note 19)
|
--
|
--
|
64.8
|
|||||||||
Other cash proceeds
|
73.5
|
57.6
|
41.1
|
|||||||||
Total
|
$
|
1,198.8
|
$
|
1,053.8
|
$
|
105.9
|
|
For Year Ended December 31,
|
|||||||||||
|
2012
|
2011
|
2010
|
|||||||||
Sale of Energy Transfer Equity common units (see Note 9)
|
$
|
68.8
|
$
|
27.2
|
$
|
--
|
||||||
Sale of ownership interests in Crystal (see Note 8)
|
--
|
129.1
|
--
|
|||||||||
Insurance recoveries attributable to West Storage claims (see Note 19)
|
30.0
|
4.7
|
--
|
|||||||||
Insurance settlement attributable to disposal of certain offshore assets (see Note 19)
|
--
|
--
|
56.6
|
|||||||||
Other losses, net
|
(12.4
|
)
|
(5.3
|
)
|
(9.9
|
)
|
||||||
Total
|
$
|
86.4
|
$
|
155.7
|
$
|
46.7
|
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
||||||||||||
For the Year Ended December 31, 2012:
|
||||||||||||||||
Revenues
|
$
|
11,252.5
|
$
|
9,789.8
|
$
|
10,468.7
|
$
|
11,072.1
|
||||||||
Operating income
|
748.9
|
749.1
|
788.5
|
822.7
|
||||||||||||
Net income
|
655.5
|
567.2
|
587.9
|
617.4
|
||||||||||||
Net income attributable to limited partners
|
651.3
|
566.3
|
586.8
|
615.5
|
||||||||||||
|
||||||||||||||||
Earnings per unit:
|
||||||||||||||||
Basic
|
$
|
0.76
|
$
|
0.66
|
$
|
0.68
|
$
|
0.70
|
||||||||
Diluted
|
$
|
0.73
|
$
|
0.64
|
$
|
0.66
|
$
|
0.68
|
||||||||
|
||||||||||||||||
For the Year Ended December 31, 2011:
|
||||||||||||||||
Revenues
|
$
|
10,183.7
|
$
|
11,216.5
|
$
|
11,327.1
|
$
|
11,585.7
|
||||||||
Operating income
|
624.9
|
643.9
|
681.1
|
909.2
|
||||||||||||
Net income
|
434.5
|
448.5
|
479.5
|
725.8
|
||||||||||||
Net income attributable to limited partners
|
420.7
|
433.7
|
471.4
|
721.1
|
||||||||||||
|
||||||||||||||||
Earnings per unit:
|
||||||||||||||||
Basic
|
$
|
0.52
|
$
|
0.53
|
$
|
0.57
|
$
|
0.85
|
||||||||
Diluted
|
$
|
0.49
|
$
|
0.51
|
$
|
0.55
|
$
|
0.82
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and
Subsidiaries
Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
ASSETS
|
||||||||||||||||||||||||||||
Current assets:
|
||||||||||||||||||||||||||||
Cash and cash equivalents and restricted cash
|
$
|
4.3
|
$
|
28.0
|
$
|
(12.1
|
)
|
$
|
20.2
|
$
|
0.2
|
$
|
--
|
$
|
20.4
|
|||||||||||||
Accounts receivable – trade, net
|
1,585.2
|
2,768.7
|
(3.0
|
)
|
4,350.9
|
--
|
--
|
4,350.9
|
||||||||||||||||||||
Accounts receivable – related parties
|
180.5
|
1,372.8
|
(1,550.8
|
)
|
2.5
|
(0.6
|
)
|
0.6
|
2.5
|
|||||||||||||||||||
Inventories
|
853.6
|
235.6
|
(0.8
|
)
|
1,088.4
|
--
|
--
|
1,088.4
|
||||||||||||||||||||
Prepaid and other current assets
|
154.9
|
231.8
|
(5.8
|
)
|
380.9
|
--
|
--
|
380.9
|
||||||||||||||||||||
Total current assets
|
2,778.5
|
4,636.9
|
(1,572.5
|
)
|
5,842.9
|
(0.4
|
)
|
0.6
|
5,843.1
|
|||||||||||||||||||
Property, plant and equipment, net
|
1,673.6
|
23,170.8
|
2.0
|
24,846.4
|
--
|
--
|
24,846.4
|
|||||||||||||||||||||
Investments in unconsolidated affiliates
|
28,454.4
|
1,846.9
|
(28,906.7
|
)
|
1,394.6
|
13,188.0
|
(13,188.0
|
)
|
1,394.6
|
|||||||||||||||||||
Intangible assets, net
|
78.5
|
1,488.3
|
--
|
1,566.8
|
--
|
--
|
1,566.8
|
|||||||||||||||||||||
Goodwill
|
458.9
|
1,627.9
|
--
|
2,086.8
|
--
|
--
|
2,086.8
|
|||||||||||||||||||||
Other assets
|
126.0
|
71.4
|
(0.9
|
)
|
196.5
|
0.2
|
--
|
196.7
|
||||||||||||||||||||
Total assets
|
$
|
33,569.9
|
$
|
32,842.2
|
$
|
(30,478.1
|
)
|
$
|
35,934.0
|
$
|
13,187.8
|
$
|
(13,187.4
|
)
|
$
|
35,934.4
|
||||||||||||
|
||||||||||||||||||||||||||||
LIABILITIES AND EQUITY
|
||||||||||||||||||||||||||||
Current liabilities:
|
||||||||||||||||||||||||||||
Current maturities of debt
|
$
|
1,516.7
|
$
|
29.9
|
$
|
--
|
$
|
1,546.6
|
$
|
--
|
$
|
--
|
$
|
1,546.6
|
||||||||||||||
Accounts payable – trade
|
226.7
|
549.8
|
(12.1
|
)
|
764.4
|
0.1
|
--
|
764.5
|
||||||||||||||||||||
Accounts payable – related parties
|
1,584.2
|
92.9
|
(1,550.6
|
)
|
126.5
|
--
|
0.6
|
127.1
|
||||||||||||||||||||
Accrued product payables
|
1,851.8
|
2,628.4
|
(4.0
|
)
|
4,476.2
|
--
|
--
|
4,476.2
|
||||||||||||||||||||
Accrued interest
|
300.1
|
0.7
|
--
|
300.8
|
--
|
--
|
300.8
|
|||||||||||||||||||||
Other current liabilities
|
266.5
|
280.0
|
(5.8
|
)
|
540.7
|
--
|
(0.2
|
)
|
540.5
|
|||||||||||||||||||
Total current liabilities
|
5,746.0
|
3,581.7
|
(1,572.5
|
)
|
7,755.2
|
0.1
|
0.4
|
7,755.7
|
||||||||||||||||||||
Long-term debt
|
14,640.2
|
15.0
|
--
|
14,655.2
|
--
|
--
|
14,655.2
|
|||||||||||||||||||||
Deferred tax liabilities
|
5.1
|
17.7
|
(0.9
|
)
|
21.9
|
--
|
0.6
|
22.5
|
||||||||||||||||||||
Other long-term liabilities
|
15.6
|
189.4
|
--
|
205.0
|
--
|
--
|
205.0
|
|||||||||||||||||||||
Commitments and contingencies
|
||||||||||||||||||||||||||||
Equity:
|
||||||||||||||||||||||||||||
Partners' and other owners' equity
|
13,163.0
|
28,963.7
|
(28,961.1
|
)
|
13,165.6
|
13,187.7
|
(13,165.6
|
)
|
13,187.7
|
|||||||||||||||||||
Noncontrolling interests
|
--
|
74.7
|
56.4
|
131.1
|
--
|
(22.8
|
)
|
108.3
|
||||||||||||||||||||
Total equity
|
13,163.0
|
29,038.4
|
(28,904.7
|
)
|
13,296.7
|
13,187.7
|
(13,188.4
|
)
|
13,296.0
|
|||||||||||||||||||
Total liabilities and equity
|
$
|
33,569.9
|
$
|
32,842.2
|
$
|
(30,478.1
|
)
|
$
|
35,934.0
|
$
|
13,187.8
|
$
|
(13,187.4
|
)
|
$
|
35,934.4
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and
Subsidiaries
Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
ASSETS
|
||||||||||||||||||||||||||||
Current assets:
|
||||||||||||||||||||||||||||
Cash and cash equivalents and restricted cash
|
$
|
48.2
|
$
|
21.3
|
$
|
(11.2
|
)
|
$
|
58.3
|
$
|
--
|
$
|
--
|
$
|
58.3
|
|||||||||||||
Accounts receivable – trade, net
|
1,599.4
|
2,913.2
|
(10.8
|
)
|
4,501.8
|
--
|
--
|
4,501.8
|
||||||||||||||||||||
Accounts receivable – related parties
|
141.1
|
2,155.5
|
(2,252.0
|
)
|
44.6
|
(1.1
|
)
|
--
|
43.5
|
|||||||||||||||||||
Inventories
|
943.6
|
170.5
|
(2.4
|
)
|
1,111.7
|
--
|
--
|
1,111.7
|
||||||||||||||||||||
Prepaid and other current assets
|
216.8
|
152.6
|
(16.0
|
)
|
353.4
|
--
|
--
|
353.4
|
||||||||||||||||||||
Total current assets
|
2,949.1
|
5,413.1
|
(2,292.4
|
)
|
6,069.8
|
(1.1
|
)
|
--
|
6,068.7
|
|||||||||||||||||||
Property, plant and equipment, net
|
1,477.5
|
20,723.7
|
(9.6
|
)
|
22,191.6
|
--
|
--
|
22,191.6
|
||||||||||||||||||||
Investments in unconsolidated affiliates
|
27,060.0
|
8,266.7
|
(33,467.1
|
)
|
1,859.6
|
12,114.5
|
(12,114.5
|
)
|
1,859.6
|
|||||||||||||||||||
Intangible assets, net
|
142.4
|
1,527.4
|
(13.6
|
)
|
1,656.2
|
--
|
--
|
1,656.2
|
||||||||||||||||||||
Goodwill
|
458.9
|
1,633.4
|
--
|
2,092.3
|
--
|
--
|
2,092.3
|
|||||||||||||||||||||
Other assets
|
146.4
|
107.5
|
2.8
|
256.7
|
--
|
--
|
256.7
|
|||||||||||||||||||||
Total assets
|
$
|
32,234.3
|
$
|
37,671.8
|
$
|
(35,779.9
|
)
|
$
|
34,126.2
|
$
|
12,113.4
|
$
|
(12,114.5
|
)
|
$
|
34,125.1
|
||||||||||||
|
||||||||||||||||||||||||||||
LIABILITIES AND EQUITY
|
||||||||||||||||||||||||||||
Current liabilities:
|
||||||||||||||||||||||||||||
Current maturities of debt
|
$
|
500.0
|
$
|
--
|
$
|
--
|
$
|
500.0
|
$
|
--
|
$
|
--
|
$
|
500.0
|
||||||||||||||
Accounts payable – trade
|
205.6
|
578.6
|
(11.2
|
)
|
773.0
|
--
|
--
|
773.0
|
||||||||||||||||||||
Accounts payable – related parties
|
2,407.2
|
71.9
|
(2,267.5
|
)
|
211.6
|
--
|
--
|
211.6
|
||||||||||||||||||||
Accrued product payables
|
2,141.0
|
2,912.4
|
(6.3
|
)
|
5,047.1
|
--
|
--
|
5,047.1
|
||||||||||||||||||||
Accrued interest
|
287.1
|
1.0
|
--
|
288.1
|
--
|
--
|
288.1
|
|||||||||||||||||||||
Other current liabilities
|
298.1
|
321.8
|
(7.4
|
)
|
612.5
|
--
|
0.1
|
612.6
|
||||||||||||||||||||
Total current liabilities
|
5,839.0
|
3,885.7
|
(2,292.4
|
)
|
7,432.3
|
--
|
0.1
|
7,432.4
|
||||||||||||||||||||
Long-term debt
|
13,975.1
|
54.3
|
--
|
14,029.4
|
--
|
--
|
14,029.4
|
|||||||||||||||||||||
Deferred tax liabilities
|
22.2
|
67.1
|
2.8
|
92.1
|
--
|
(0.9
|
)
|
91.2
|
||||||||||||||||||||
Other long-term liabilities
|
155.3
|
197.5
|
--
|
352.8
|
--
|
--
|
352.8
|
|||||||||||||||||||||
Commitments and contingencies
|
||||||||||||||||||||||||||||
Equity:
|
||||||||||||||||||||||||||||
Partners' and other owners' equity
|
12,242.7
|
28,799.8
|
(28,946.4
|
)
|
12,096.1
|
12,113.4
|
(12,096.1
|
)
|
12,113.4
|
|||||||||||||||||||
Noncontrolling interests
|
--
|
4,667.4
|
(4,543.9
|
)
|
123.5
|
--
|
(17.6
|
)
|
105.9
|
|||||||||||||||||||
Total equity
|
12,242.7
|
33,467.2
|
(33,490.3
|
)
|
12,219.6
|
12,113.4
|
(12,113.7
|
)
|
12,219.3
|
|||||||||||||||||||
Total liabilities and equity
|
$
|
32,234.3
|
$
|
37,671.8
|
$
|
(35,779.9
|
)
|
$
|
34,126.2
|
$
|
12,113.4
|
$
|
(12,114.5
|
)
|
$
|
34,125.1
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and Subsidiaries
Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Revenues
|
$
|
29,654.7
|
$
|
28,221.5
|
$
|
(15,293.1
|
)
|
$
|
42,583.1
|
$
|
--
|
$
|
--
|
$
|
42,583.1
|
|||||||||||||
Costs and expenses:
|
||||||||||||||||||||||||||||
Operating costs and expenses
|
28,839.1
|
25,821.8
|
(15,293.0
|
)
|
39,367.9
|
--
|
--
|
39,367.9
|
||||||||||||||||||||
General and administrative costs
|
26.1
|
142.7
|
--
|
168.8
|
1.5
|
--
|
170.3
|
|||||||||||||||||||||
Total costs and expenses
|
28,865.2
|
25,964.5
|
(15,293.0
|
)
|
39,536.7
|
1.5
|
--
|
39,538.2
|
||||||||||||||||||||
Equity in income of unconsolidated affiliates
|
2,381.8
|
80.7
|
(2,398.2
|
)
|
64.3
|
2,421.4
|
(2,421.4
|
)
|
64.3
|
|||||||||||||||||||
Operating income
|
3,171.3
|
2,337.7
|
(2,398.3
|
)
|
3,110.7
|
2,419.9
|
(2,421.4
|
)
|
3,109.2
|
|||||||||||||||||||
Other income (expense):
|
||||||||||||||||||||||||||||
Interest expense
|
(767.1
|
)
|
(4.7
|
)
|
--
|
(771.8
|
)
|
--
|
--
|
(771.8
|
)
|
|||||||||||||||||
Other, net
|
0.1
|
73.3
|
--
|
73.4
|
--
|
--
|
73.4
|
|||||||||||||||||||||
Total other expense, net
|
(767.0
|
)
|
68.6
|
--
|
(698.4
|
)
|
--
|
--
|
(698.4
|
)
|
||||||||||||||||||
Income before income taxes
|
2,404.3
|
2,406.3
|
(2,398.3
|
)
|
2,412.3
|
2,419.9
|
(2,421.4
|
)
|
2,410.8
|
|||||||||||||||||||
Provision for income taxes
|
15.7
|
2.4
|
--
|
18.1
|
--
|
(0.9
|
)
|
17.2
|
||||||||||||||||||||
Net income
|
2,420.0
|
2,408.7
|
(2,398.3
|
)
|
2,430.4
|
2,419.9
|
(2,422.3
|
)
|
2,428.0
|
|||||||||||||||||||
Net loss (income) attributable to noncontrolling interests
|
--
|
(5.1
|
)
|
(5.3
|
)
|
(10.4
|
)
|
--
|
2.3
|
(8.1
|
)
|
|||||||||||||||||
Net income attributable to entity
|
$
|
2,420.0
|
$
|
2,403.6
|
$
|
(2,403.6
|
)
|
$
|
2,420.0
|
$
|
2,419.9
|
$
|
(2,420.0
|
)
|
$
|
2,419.9
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and Subsidiaries
Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Revenues
|
$
|
33,063.8
|
$
|
27,971.8
|
$
|
(16,722.6
|
)
|
$
|
44,313.0
|
$
|
--
|
$
|
--
|
$
|
44,313.0
|
|||||||||||||
Costs and expenses:
|
||||||||||||||||||||||||||||
Operating costs and expenses
|
32,432.7
|
25,609.7
|
(16,723.9
|
)
|
41,318.5
|
--
|
--
|
41,318.5
|
||||||||||||||||||||
General and administrative costs
|
10.4
|
163.7
|
--
|
174.1
|
7.7
|
--
|
181.8
|
|||||||||||||||||||||
Total costs and expenses
|
32,443.1
|
25,773.4
|
(16,723.9
|
)
|
41,492.6
|
7.7
|
--
|
41,500.3
|
||||||||||||||||||||
Equity in income of unconsolidated affiliates
|
2,194.4
|
131.7
|
(2,279.7
|
)
|
46.4
|
2,054.6
|
(2,054.6
|
)
|
46.4
|
|||||||||||||||||||
Operating income
|
2,815.1
|
2,330.1
|
(2,278.4
|
)
|
2,866.8
|
2,046.9
|
(2,054.6
|
)
|
2,859.1
|
|||||||||||||||||||
Other income (expense):
|
||||||||||||||||||||||||||||
Interest expense
|
(725.1
|
)
|
(26.4
|
)
|
7.4
|
(744.1
|
)
|
--
|
--
|
(744.1
|
)
|
|||||||||||||||||
Other, net
|
7.8
|
0.1
|
(7.4
|
)
|
0.5
|
--
|
--
|
0.5
|
||||||||||||||||||||
Total other expense, net
|
(717.3
|
)
|
(26.3
|
)
|
--
|
(743.6
|
)
|
--
|
--
|
(743.6
|
)
|
|||||||||||||||||
Income before income taxes
|
2,097.8
|
2,303.8
|
(2,278.4
|
)
|
2,123.2
|
2,046.9
|
(2,054.6
|
)
|
2,115.5
|
|||||||||||||||||||
Provision for income taxes
|
(45.3
|
)
|
18.4
|
--
|
(26.9
|
)
|
--
|
(0.3
|
)
|
(27.2
|
)
|
|||||||||||||||||
Net income
|
2,052.5
|
2,322.2
|
(2,278.4
|
)
|
2,096.3
|
2,046.9
|
(2,054.9
|
)
|
2,088.3
|
|||||||||||||||||||
Net loss (income) attributable to noncontrolling interests
|
--
|
(51.7
|
)
|
9.2
|
(42.5
|
)
|
--
|
1.1
|
(41.4
|
)
|
||||||||||||||||||
Net income attributable to entity
|
$
|
2,052.5
|
$
|
2,270.5
|
$
|
(2,269.2
|
)
|
$
|
2,053.8
|
$
|
2,046.9
|
$
|
(2,053.8
|
)
|
$
|
2,046.9
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and Subsidiaries
Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Revenues
|
$
|
26,152.3
|
$
|
19,791.6
|
$
|
(12,204.6
|
)
|
$
|
33,739.3
|
$
|
--
|
$
|
--
|
$
|
33,739.3
|
|||||||||||||
Costs and expenses:
|
||||||||||||||||||||||||||||
Operating costs and expenses
|
25,748.9
|
17,906.6
|
(12,206.2
|
)
|
31,449.3
|
--
|
--
|
31,449.3
|
||||||||||||||||||||
General and administrative costs
|
15.7
|
183.6
|
--
|
199.3
|
5.5
|
--
|
204.8
|
|||||||||||||||||||||
Total costs and expenses
|
25,764.6
|
18,090.2
|
(12,206.2
|
)
|
31,648.6
|
5.5
|
--
|
31,654.1
|
||||||||||||||||||||
Equity in income of unconsolidated affiliates
|
1,692.7
|
133.3
|
(1,764.0
|
)
|
62.0
|
1,427.2
|
(1,427.2
|
)
|
62.0
|
|||||||||||||||||||
Operating income
|
2,080.4
|
1,834.7
|
(1,762.4
|
)
|
2,152.7
|
1,421.7
|
(1,427.2
|
)
|
2,147.2
|
|||||||||||||||||||
Other income (expense):
|
||||||||||||||||||||||||||||
Interest expense
|
(653.4
|
)
|
(99.0
|
)
|
10.5
|
(741.9
|
)
|
--
|
--
|
(741.9
|
)
|
|||||||||||||||||
Other, net
|
11.0
|
4.0
|
(10.5
|
)
|
4.5
|
--
|
--
|
4.5
|
||||||||||||||||||||
Total other expense, net
|
(642.4
|
)
|
(95.0
|
)
|
--
|
(737.4
|
)
|
--
|
--
|
(737.4
|
)
|
|||||||||||||||||
Income before income taxes
|
1,438.0
|
1,739.7
|
(1,762.4
|
)
|
1,415.3
|
1,421.7
|
(1,427.2
|
)
|
1,409.8
|
|||||||||||||||||||
Provision for income taxes
|
(12.8
|
)
|
(13.0
|
)
|
--
|
(25.8
|
)
|
--
|
(0.3
|
)
|
(26.1
|
)
|
||||||||||||||||
Net income
|
1,425.2
|
1,726.7
|
(1,762.4
|
)
|
1,389.5
|
1,421.7
|
(1,427.5
|
)
|
1,383.7
|
|||||||||||||||||||
Net loss (income) attributable to noncontrolling interests
|
--
|
17.6
|
(80.9
|
)
|
(63.3
|
)
|
--
|
(999.6
|
)
|
(1,062.9
|
)
|
|||||||||||||||||
Net income attributable to entity
|
$
|
1,425.2
|
$
|
1,744.3
|
$
|
(1,843.3
|
)
|
$
|
1,326.2
|
$
|
1,421.7
|
$
|
(2,427.1
|
)
|
$
|
320.8
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and
Subsidiaries
Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Comprehensive income
|
$
|
2,375.8
|
$
|
2,433.9
|
$
|
(2,398.3
|
)
|
$
|
2,411.4
|
$
|
2,400.9
|
$
|
(2,403.3
|
)
|
$
|
2,409.0
|
||||||||||||
Comprehensive income attributable to noncontrolling interests
|
--
|
(5.1
|
)
|
(5.3
|
)
|
(10.4
|
)
|
--
|
2.3
|
(8.1
|
)
|
|||||||||||||||||
Comprehensive income attributable to entity
|
$
|
2,375.8
|
$
|
2,428.8
|
|
$
|
(2,403.6
|
)
|
$
|
2,401.0
|
$
|
2,400.9
|
$
|
(2,401.0
|
)
|
$
|
2,400.9
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and
Subsidiaries
Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Comprehensive income
|
$
|
1,737.4
|
$
|
2,319.4
|
$
|
(2,278.3
|
)
|
$
|
1,778.5
|
$
|
1,729.1
|
$
|
(1,737.1
|
)
|
$
|
1,770.5
|
||||||||||||
Comprehensive income attributable to noncontrolling interests
|
--
|
(51.7
|
)
|
9.2
|
(42.5
|
)
|
--
|
1.1
|
(41.4
|
)
|
||||||||||||||||||
Comprehensive income attributable to entity
|
$
|
1,737.4
|
$
|
2,267.7
|
$
|
(2,269.1
|
)
|
$
|
1,736.0
|
$
|
1,729.1
|
$
|
(1,736.0
|
)
|
$
|
1,729.1
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and
Subsidiaries
Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Comprehensive income
|
$
|
1,430.7
|
$
|
1,725.7
|
$
|
(1,762.5
|
)
|
$
|
1,393.9
|
$
|
322.9
|
$
|
(328.8
|
)
|
$
|
1,388.0
|
||||||||||||
Comprehensive income attributable to noncontrolling interests
|
--
|
(21.2
|
)
|
(44.3
|
)
|
(65.5
|
)
|
--
|
(999.6
|
)
|
(1,065.1
|
)
|
||||||||||||||||
Comprehensive income attributable to entity
|
$
|
1,430.7
|
$
|
1,704.5
|
$
|
(1,806.8
|
)
|
$
|
1,328.4
|
$
|
322.9
|
$
|
(1,328.4
|
)
|
$
|
322.9
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and Subsidiaries Eliminations
and
Adjustments
|
Consolidated
EPO and Subsidiaries
|
Enterprise
Products
Partners
L.P.
(Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Operating activities:
|
||||||||||||||||||||||||||||
Net income
|
$
|
2,420.0
|
$
|
2,408.7
|
$
|
(2,398.3
|
)
|
$
|
2,430.4
|
$
|
2,419.9
|
$
|
(2,422.3
|
)
|
$
|
2,428.0
|
||||||||||||
Reconciliation of net income to net cash flows provided by operating activities:
|
||||||||||||||||||||||||||||
Depreciation, amortization and accretion
|
118.0
|
986.9
|
--
|
1,104.9
|
--
|
--
|
1,104.9
|
|||||||||||||||||||||
Equity in income of unconsolidated affiliates
|
(2,381.8
|
)
|
(80.7
|
)
|
2,398.2
|
(64.3
|
)
|
(2,421.4
|
)
|
2,421.4
|
(64.3
|
)
|
||||||||||||||||
Distributions received from unconsolidated affiliates
|
3,918.9
|
106.6
|
(3,908.8
|
)
|
116.7
|
2,209.3
|
(2,209.3
|
)
|
116.7
|
|||||||||||||||||||
Net effect of changes in operating accounts and other operating activities
|
(2,174.9
|
)
|
1,485.3
|
(0.8
|
)
|
(690.4
|
)
|
(4.9
|
)
|
0.9
|
(694.4
|
)
|
||||||||||||||||
Net cash flows provided by operating activities
|
1,900.2
|
4,906.8
|
(3,909.7
|
)
|
2,897.3
|
2,202.9
|
(2,209.3
|
)
|
2,890.9
|
|||||||||||||||||||
Investing activities:
|
||||||||||||||||||||||||||||
Capital expenditures, net of contributions in aid of construction costs
|
(219.5
|
)
|
(3,379.0
|
)
|
--
|
(3,598.5
|
)
|
--
|
--
|
(3,598.5
|
)
|
|||||||||||||||||
Proceeds from disposal of assets
|
1,137.2
|
61.6
|
--
|
1,198.8
|
--
|
--
|
1,198.8
|
|||||||||||||||||||||
Other investing activities
|
(2,961.4
|
)
|
(432.3
|
)
|
2,774.6
|
(619.1
|
)
|
(816.2
|
)
|
816.2
|
(619.1
|
)
|
||||||||||||||||
Cash used in investing activities
|
(2,043.7
|
)
|
(3,749.7
|
)
|
2,774.6
|
(3,018.8
|
)
|
(816.2
|
)
|
816.2
|
(3,018.8
|
)
|
||||||||||||||||
Financing activities:
|
||||||||||||||||||||||||||||
Borrowings under debt agreements
|
8,363.1
|
|
--
|
--
|
8,363.1
|
|
--
|
--
|
8,363.1
|
|||||||||||||||||||
Repayments of debt
|
(6,666.9
|
)
|
(9.5
|
)
|
--
|
(6,676.4
|
)
|
--
|
--
|
(6,676.4
|
)
|
|||||||||||||||||
Cash distributions paid to partners
|
(2,209.3
|
)
|
(3,922.1
|
)
|
3,922.1
|
(2,209.3
|
)
|
(2,178.6
|
)
|
2,209.3
|
(2,178.6
|
)
|
||||||||||||||||
Cash distributions paid to noncontrolling interests
|
--
|
--
|
(13.3
|
)
|
(13.3
|
)
|
--
|
--
|
(13.3
|
)
|
||||||||||||||||||
Cash contributions from noncontrolling interests
|
--
|
--
|
6.6
|
6.6
|
--
|
--
|
6.6
|
|||||||||||||||||||||
Net cash proceeds from issuance of common units
|
--
|
--
|
--
|
--
|
816.8
|
--
|
816.8
|
|||||||||||||||||||||
Cash contributions from owners
|
816.2
|
2,781.2
|
(2,781.2
|
)
|
816.2
|
--
|
(816.2
|
)
|
--
|
|||||||||||||||||||
Other financing activities
|
(169.3
|
)
|
--
|
--
|
(169.3
|
)
|
(24.7
|
)
|
--
|
(194.0
|
)
|
|||||||||||||||||
Cash provided by (used in) financing activities
|
133.8
|
(1,150.4
|
)
|
1,134.2
|
117.6
|
(1,386.5
|
)
|
1,393.1
|
124.2
|
|||||||||||||||||||
Net change in cash and cash equivalents
|
(9.7
|
)
|
6.7
|
(0.9
|
)
|
(3.9
|
)
|
0.2
|
--
|
(3.7
|
)
|
|||||||||||||||||
Cash and cash equivalents, January 1
|
9.7
|
21.3
|
(11.2
|
)
|
19.8
|
--
|
--
|
19.8
|
||||||||||||||||||||
Cash and cash equivalents, December 31
|
$
|
--
|
$
|
28.0
|
$
|
(12.1
|
)
|
$
|
15.9
|
$
|
0.2
|
$
|
--
|
$
|
16.1
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and Subsidiaries Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P. (Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Operating activities:
|
||||||||||||||||||||||||||||
Net income
|
$
|
2,052.5
|
$
|
2,322.2
|
$
|
(2,278.4
|
)
|
$
|
2,096.3
|
$
|
2,046.9
|
$
|
(2,054.9
|
)
|
$
|
2,088.3
|
||||||||||||
Reconciliation of net income to net cash flows provided by operating activities:
|
||||||||||||||||||||||||||||
Depreciation, amortization and accretion
|
119.7
|
888.7
|
(1.4
|
)
|
1,007.0
|
--
|
--
|
1,007.0
|
||||||||||||||||||||
Equity in income of unconsolidated affiliates
|
(2,194.4
|
)
|
(131.7
|
)
|
2,279.7
|
(46.4
|
)
|
(2,054.6
|
)
|
2,054.6
|
(46.4
|
)
|
||||||||||||||||
Distributions received from unconsolidated affiliates
|
150.3
|
196.8
|
(190.7
|
)
|
156.4
|
1,994.9
|
(1,994.9
|
)
|
156.4
|
|||||||||||||||||||
Net effect of changes in operating accounts and other operating activities
|
1,036.4
|
(118.5
|
)
|
(789.8
|
)
|
128.1
|
(3.4
|
)
|
0.5
|
125.2
|
||||||||||||||||||
Net cash flows provided by operating activities
|
1,164.5
|
3,157.5
|
(980.6
|
)
|
3,341.4
|
1,983.8
|
(1,994.7
|
)
|
3,330.5
|
|||||||||||||||||||
Investing activities:
|
||||||||||||||||||||||||||||
Capital expenditures, net of contributions in aid of construction costs
|
(63.4
|
)
|
(3,779.2
|
)
|
--
|
(3,842.6
|
)
|
--
|
--
|
(3,842.6
|
)
|
|||||||||||||||||
Proceeds from disposal of assets
|
611.5
|
442.3
|
--
|
1,053.8
|
--
|
--
|
1,053.8
|
|||||||||||||||||||||
Other investing activities
|
(1,991.7
|
)
|
(1,312.6
|
)
|
3,315.5
|
11.2
|
(546.9
|
)
|
546.9
|
11.2
|
||||||||||||||||||
Cash used in investing activities
|
(1,443.6
|
)
|
(4,649.5
|
)
|
3,315.5
|
(2,777.6
|
)
|
(546.9
|
)
|
546.9
|
(2,777.6
|
)
|
||||||||||||||||
Financing activities:
|
||||||||||||||||||||||||||||
Borrowings under debt agreements
|
7,764.1
|
560.0
|
--
|
8,324.1
|
--
|
--
|
8,324.1
|
|||||||||||||||||||||
Repayments of debt
|
(5,970.0
|
)
|
(1,405.8
|
)
|
--
|
(7,375.8
|
)
|
--
|
--
|
(7,375.8
|
)
|
|||||||||||||||||
Cash distributions paid to partners
|
(1,994.9
|
)
|
(946.8
|
)
|
946.8
|
(1,994.9
|
)
|
(1,974.3
|
)
|
1,994.9
|
(1,974.3
|
)
|
||||||||||||||||
Cash distributions paid to noncontrolling interests
|
--
|
(108.1
|
)
|
47.4
|
(60.7
|
)
|
--
|
--
|
(60.7
|
)
|
||||||||||||||||||
Cash contributions from noncontrolling interests
|
--
|
724.8
|
(716.1
|
)
|
8.7
|
--
|
(0.2
|
)
|
8.5
|
|||||||||||||||||||
Net cash proceeds from issuance of common units
|
--
|
--
|
--
|
--
|
542.9
|
--
|
542.9
|
|||||||||||||||||||||
Cash contributions from owners
|
546.9
|
2,621.3
|
(2,621.3
|
)
|
546.9
|
--
|
(546.9
|
)
|
--
|
|||||||||||||||||||
Other financing activities
|
(57.8
|
)
|
--
|
--
|
(57.8
|
)
|
(5.5
|
)
|
--
|
(63.3
|
)
|
|||||||||||||||||
Cash provided by (used in) financing activities
|
288.3
|
1,445.4
|
(2,343.2
|
)
|
(609.5
|
)
|
(1,436.9
|
)
|
1,447.8
|
(598.6
|
)
|
|||||||||||||||||
Net change in cash and cash equivalents
|
9.2
|
(46.6
|
)
|
(8.3
|
)
|
(45.7
|
)
|
--
|
--
|
(45.7
|
)
|
|||||||||||||||||
Cash and cash equivalents, January 1
|
0.5
|
67.9
|
(2.9
|
)
|
65.5
|
--
|
--
|
65.5
|
||||||||||||||||||||
Cash and cash equivalents, December 31
|
$
|
9.7
|
$
|
21.3
|
$
|
(11.2
|
)
|
$
|
19.8
|
$
|
--
|
$
|
--
|
$
|
19.8
|
|
EPO and Subsidiaries
|
|||||||||||||||||||||||||||
|
Subsidiary
Issuer
(EPO)
|
Other
Subsidiaries
(Non-
guarantor)
|
EPO and Subsidiaries Eliminations
and
Adjustments
|
Consolidated
EPO and
Subsidiaries
|
Enterprise
Products
Partners
L.P. (Guarantor)
|
Eliminations
and
Adjustments
|
Consolidated
Total
|
|||||||||||||||||||||
Operating activities:
|
||||||||||||||||||||||||||||
Net income
|
$
|
1,425.2
|
$
|
1,726.7
|
$
|
(1,762.4
|
)
|
$
|
1,389.5
|
$
|
1,421.7
|
$
|
(1,427.5
|
)
|
$
|
1,383.7
|
||||||||||||
Reconciliation of net income to net cash flows provided by operating activities:
|
||||||||||||||||||||||||||||
Depreciation, amortization and accretion
|
109.2
|
877.3
|
(1.4
|
)
|
985.1
|
--
|
--
|
985.1
|
||||||||||||||||||||
Equity in income of unconsolidated affiliates
|
(1,692.7
|
)
|
(133.3
|
)
|
1,764.0
|
(62.0
|
)
|
(1,427.2
|
)
|
1,427.2
|
(62.0
|
)
|
||||||||||||||||
Distributions received from unconsolidated affiliates
|
186.1
|
244.5
|
(238.7
|
)
|
191.9
|
1,714.4
|
(1,714.4
|
)
|
191.9
|
|||||||||||||||||||
Net effect of changes in operating accounts and other operating activities
|
28.6
|
609.5
|
(840.9
|
)
|
(202.8
|
)
|
(275.8
|
)
|
279.9
|
(198.7
|
)
|
|||||||||||||||||
Net cash flows provided by operating activities
|
56.4
|
3,324.7
|
(1,079.4
|
)
|
2,301.7
|
1,433.1
|
(1,434.8
|
)
|
2,300.0
|
|||||||||||||||||||
Investing activities:
|
||||||||||||||||||||||||||||
Capital expenditures, net of contributions in aid of construction costs
|
(19.2
|
)
|
(1,982.9
|
)
|
--
|
(2,002.1
|
)
|
--
|
--
|
(2,002.1
|
)
|
|||||||||||||||||
Cash used for business combinations
|
(40.7
|
)
|
(1,273.2
|
)
|
--
|
(1,313.9
|
)
|
--
|
--
|
(1,313.9
|
)
|
|||||||||||||||||
Other investing activities
|
(1,827.3
|
)
|
144.3
|
1,747.4
|
64.4
|
(1,653.6
|
)
|
1,653.6
|
64.4
|
|||||||||||||||||||
Cash used in investing activities
|
(1,887.2
|
)
|
(3,111.8
|
)
|
1,747.4
|
(3,251.6
|
)
|
(1,653.6
|
)
|
1,653.6
|
(3,251.6
|
)
|
||||||||||||||||
Financing activities:
|
||||||||||||||||||||||||||||
Borrowings under debt agreements
|
5,977.7
|
506.7
|
--
|
6,484.4
|
--
|
--
|
6,484.4
|
|||||||||||||||||||||
Repayments of debt
|
(4,085.8
|
)
|
(1,258.6
|
)
|
--
|
(5,344.4
|
)
|
--
|
--
|
(5,344.4
|
)
|
|||||||||||||||||
Cash distributions paid to partners
|
(1,714.4
|
)
|
(1,217.1
|
)
|
1,186.7
|
(1,744.8
|
)
|
(307.7
|
)
|
1,744.8
|
(307.7
|
)
|
||||||||||||||||
Cash distributions paid to noncontrolling interests
|
--
|
(117.7
|
)
|
44.7
|
(73.0
|
)
|
--
|
(1,394.8
|
)
|
(1,467.8
|
)
|
|||||||||||||||||
Cash contributions from noncontrolling interests
|
--
|
517.6
|
(512.8
|
)
|
4.8
|
--
|
1,091.7
|
1,096.5
|
||||||||||||||||||||
Net cash proceeds from issuance of common units
|
--
|
--
|
--
|
--
|
528.5
|
--
|
528.5
|
|||||||||||||||||||||
Cash contributions from owners
|
1,653.7
|
1,383.3
|
(1,383.3
|
)
|
1,653.7
|
--
|
(1,653.7
|
)
|
--
|
|||||||||||||||||||
Other financing activities
|
(14.3
|
)
|
(6.8
|
)
|
--
|
(21.1
|
)
|
(0.3
|
)
|
(7.0
|
)
|
(28.4
|
)
|
|||||||||||||||
Cash provided by (used in) financing activities
|
1,816.9
|
(192.6
|
)
|
(664.7
|
)
|
959.6
|
220.5
|
(219.0
|
)
|
961.1
|
||||||||||||||||||
Effect of exchange rate changes on cash
|
--
|
0.7
|
--
|
0.7
|
--
|
--
|
0.7
|
|||||||||||||||||||||
Net change in cash and cash equivalents
|
(13.9
|
)
|
20.3
|
3.3
|
9.7
|
--
|
(0.2
|
)
|
9.5
|
|||||||||||||||||||
Cash and cash equivalents, January 1
|
14.4
|
46.9
|
(6.2
|
)
|
55.1
|
--
|
0.2
|
55.3
|
||||||||||||||||||||
Cash and cash equivalents, December 31
|
$
|
0.5
|
$
|
67.9
|
$
|
(2.9
|
)
|
$
|
65.5
|
$
|
--
|
$
|
--
|
$
|
65.5
|