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þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 76-0568219 | |||
(State or Other Jurisdiction of | (I.R.S. Employer Identification No.) | |||
Incorporation or Organization) |
1100 Louisiana, 10th Floor, Houston, Texas | 77002 | |||
(Address of Principal Executive Offices) | (Zip Code) |
Title of Each Class | Name of Each Exchange On Which Registered | |
Common Units | New York Stock Exchange |
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ANNUAL REPORT
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§ | capitalize on expected increases in natural gas, NGL and crude oil production resulting from development activities in the Rocky Mountain region, U.S. Gulf Coast and Gulf of Mexico; | ||
§ | maintain a balanced and diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary midstream energy assets; | ||
§ | share capital costs and risks through joint ventures or alliances with strategic partners, including those that will provide the raw materials for these growth projects or purchase the project’s end products; and | ||
§ | increase fee-based cash flows by investing in pipelines and other fee-based businesses. |
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§ | Mont Belvieu Caverns, LLC(“Mont Belvieu Caverns”), a recently formed subsidiary, which owns salt dome storage caverns located in Mont Belvieu, Texas that receive, store and deliver NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States; | ||
§ | Acadian Gas, LLC(“Acadian Gas”), which owns an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. A subsidiary of Acadian Gas owns a 49.5% equity interest in Evangeline Gas Pipeline, L.P. (“Evangeline”); | ||
§ | Sabine Propylene Pipeline L.P.(“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana; | ||
§ | Enterprise Lou-Tex Propylene Pipeline L.P.(“Lou-Tex Propylene”), which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and | ||
§ | South Texas NGL Pipelines, LLC(“South Texas NGL”), a recently formed subsidiary, which began transporting NGLs from Corpus Christi, Texas to Mont Belvieu, Texas in January 2007. South Texas NGL owns the DEP South Texas NGL Pipeline System. |
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§ | We utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses; | ||
§ | We buy natural gas from and sell natural gas to Acadian Gas in connection with our normal business activities; and | ||
§ | We are the sole shipper on the DEP South Texas NGL Pipeline System. |
§ | NGL Pipelines & Services; | ||
§ | Onshore Natural Gas Pipelines & Services; | ||
§ | Offshore Pipelines & Services; and | ||
§ | Petrochemical Services. |
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/d | = | per day | ||||
BBtus | = | billion British thermal units | ||||
Bcf | = | billion cubic feet | ||||
MBPD | = | thousand barrels per day | ||||
Mdth | = | thousand decatherms | ||||
MMBbls | = | million barrels | ||||
MMBtus | = | million British thermal units | ||||
MMcf | = | million cubic feet | ||||
Mcf | = | thousand cubic feet | ||||
TBtu | = | trillion British thermal units |
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Our | Storage | |||||||||||
Ownership | Length | Capacity | ||||||||||
Description of Asset | Location(s) | Interest | (Miles) | (MMBbls) | ||||||||
NGL pipelines: | ||||||||||||
Mid-America Pipeline System | Midwest and Western U.S. | 100% | 7,378 | |||||||||
Dixie Pipeline | South and Southeastern U.S. | 74.2%(1) | 1,370 | |||||||||
Seminole Pipeline | Texas | 90%(2) | 1,326 | |||||||||
EPD South Texas NGL System | Texas | 100% | 1,039 | |||||||||
Louisiana Pipeline System | Louisiana | Various(3) | 612 | |||||||||
Promix NGL Gathering System | Louisiana | 50% | 362 | |||||||||
DEP South Texas NGL Pipeline System | Texas | 100%(4) | 286 | |||||||||
Houston Ship Channel | Texas | 100% | 266 | |||||||||
Lou-Tex NGL | Texas, Louisiana | 100% | 204 | |||||||||
Others (5 systems)(5) | Alabama, Louisiana, Mississippi | Various | 452 | |||||||||
Total miles | 13,295 | |||||||||||
NGL and related product storage facilities by state: | ||||||||||||
Texas(6) | 125.0 | |||||||||||
Louisiana | 16.6 | |||||||||||
Mississippi | 10.9 | |||||||||||
Others (Arizona, Georgia, Iowa, Kansas, Nebraska, Oklahoma, Utah) | 9.6 | |||||||||||
Total capacity(7) | 162.1 | |||||||||||
(1) | We hold a 74.2% interest in this system through a majority owned subsidiary, Dixie Pipeline Company (“Dixie”). This reflects our acquisition of an additional 8.3% interest in Dixie in December 2006. | |
(2) | We hold a 90% interest in this system through a majority owned subsidiary, Seminole Pipeline Company (“Seminole”). | |
(3) | Of the 612 total miles for this system, we own 100% of 559 miles and 43.5% of the remaining 53 miles. | |
(4) | Reflects consolidated ownership of this system by the Operating Partnership (34%) and Duncan Energy Partners (66%). | |
(5) | Includes our Tri-States, Belle Rose, Wilprise and Chunchula pipelines located in the coastal regions of Alabama, Louisiana and Mississippi and a pipeline held by Venice Energy Services Company, L.L.C. (“VESCO”), an equity investment of ours. | |
(6) | The amount shown for Texas includes 33 underground caverns with an aggregate useable storage capacity of approximately 100 MMBbls that we own jointly with Duncan Energy Partners. These caverns are located in Mont Belvieu, Texas. | |
(7) | The 162.1 MMBbls of total useable storage capacity includes 21.3 MMBbls held under operating leases. The leased facilities are located in Texas, Louisiana and Kansas. |
§ | TheMid-America Pipeline Systemis a regulated NGL pipeline system consisting of three primary segments: the 2,568-mile Rocky Mountain pipeline, the 2,771-mile Conway North pipeline and the 2,039-mile Conway South pipeline. This system covers thirteen states: Wyoming, Utah, Colorado, New Mexico, Texas, Oklahoma, Kansas, Missouri, Nebraska, Iowa, Illinois, Minnesota and Wisconsin. 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. In addition, the Conway North segment has access to NGL supplies from Canada’s Western Sedimentary Basin through third-party connections. The Conway South pipeline connects the Conway hub with Kansas refineries and |
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transports NGLs from Conway, Kansas to the Hobbs hub. The Mid-America Pipeline System interconnects with our Seminole Pipeline at the Hobbs hub. We also own fifteen unregulated propane terminals that are an integral part of the Mid-America Pipeline System. | |||
During 2006, approximately 54% of the volumes transported on the Mid-America Pipeline System were mixed NGLs originating from natural gas processing plants located in the Permian Basin in west Texas, the Hugoton Basin of southwestern Kansas, the San Juan Basin of northwest New Mexico, and the Greater Green River Basin of southwestern Wyoming. The remaining volumes are generally purity NGL products originating from NGL fractionators in the mid-continent areas of Kansas, Oklahoma, and Texas, as well as deliveries from Canada. | |||
§ | TheDixie Pipelineis a regulated propane pipeline extending from southeast Texas and Louisiana to markets in the southeastern United States. Propane supplies transported on this system primarily originate from southeast Texas, southern Louisiana and Mississippi. This system operates in seven states: Texas, Louisiana, Mississippi, Alabama, Georgia, South Carolina and North Carolina. | ||
§ | TheSeminole Pipelineis a regulated pipeline that transports NGLs from the Hobbs hub and the Permian Basin area of west Texas to markets in southeastern Texas. NGLs originating on the Mid-America Pipeline System are the primary source of throughput for the Seminole Pipeline. | ||
§ | TheEPD South Texas NGL Systemis a network of NGL gathering and transportation pipelines located in south Texas. The system includes 379 miles of pipeline used to gather and transport mixed NGLs from our south Texas natural gas processing facilities to our south Texas NGL fractionation facilities. The pipeline system also includes approximately 660 miles of pipelines that deliver NGLs from our south Texas fractionation facilities to refineries and petrochemical plants located between Corpus Christi and Houston, Texas and within the Texas City-Houston area, as well as to common carrier NGL pipelines. | ||
§ | TheLouisiana Pipeline Systemis a network of NGL pipelines located in Louisiana. This system transports NGLs originating in southern Louisiana and Texas to refineries and petrochemical companies along the Mississippi River corridor in southern Louisiana. This system also provides transportation services for our natural gas processing plants, NGL fractionators and other facilities located in Louisiana. | ||
§ | ThePromix NGL Gathering Systemis a NGL pipeline system that gathers mixed NGLs from natural gas processing plants in Louisiana for delivery to an NGL fractionator owned by K/D/S Promix, L.L.C. (“Promix”). This gathering system is an integral part of the Promix NGL fractionation facility. Our ownership interest in this pipeline is held indirectly through our equity method investment in Promix. | ||
§ | TheDEP South Texas NGL Pipeline Systemtransports NGLs from our Shoup and Armstrong fractionation facilities in south Texas to Mont Belvieu, Texas. This system became operational in January 2007. We purchased 220 miles of this pipeline from ExxonMobil Pipeline Company in August 2006. In addition, we lease an 11-mile segment of this pipeline system from TEPPCO. The remaining 55 miles of this pipeline were either acquired from TEPPCO (10 miles) or constructed by us (45 miles). | ||
We contributed a direct 66% equity interest in South Texas NGL, our subsidiary that owns the DEP South Texas NGL Pipeline System, to Duncan Energy Partners on February 5, 2007. We own the remaining 34% direct interest in South Texas NGL. For additional information regarding this subsequent event, see “Recent Developments” within this Item 1. | |||
§ | TheHouston Ship Channelpipeline system is a collection of pipelines extending from our Houston Ship Channel import/export facility and Morgan’s Point facility to Mont Belvieu, Texas. This system is used to deliver NGL products to third-party petrochemical plants and refineries as well as to deliver feedstocks to our Mont Belvieu facilities. |
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§ | TheLou-Tex NGLpipeline system is used to provide transportation services for NGLs and refinery grade propylene between the Louisiana and Texas markets. We also use this pipeline to transport mixed NGLs from certain of our Louisiana gas processing plants to our Mont Belvieu NGL fractionation facility. |
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Net Gas | Total Gas | Net | Total | |||||||||||||||||
Our | Processing | Processing | Plant | Plant | ||||||||||||||||
Ownership | Capacity | Capacity | Capacity | Capacity | ||||||||||||||||
Description of Asset | Location(s) | Interest | (Bcf/d)(1) | (Bcf/d) | (MBPD)(1) | (MBPD) | ||||||||||||||
Natural gas processing facilities: | ||||||||||||||||||||
Toca | Louisiana | 61.4% | 0.66 | 1.10 | ||||||||||||||||
Chaco | New Mexico | 100% | 0.65 | 0.65 | ||||||||||||||||
Pioneer(2) | Wyoming | 100% | 0.60 | 0.60 | ||||||||||||||||
Yscloskey | Louisiana | 31.1% | 0.58 | 1.85 | ||||||||||||||||
North Terrebonne | Louisiana | 43.5% | 0.57 | 1.30 | ||||||||||||||||
Calumet | Louisiana | 31.2% | 0.50 | 1.60 | ||||||||||||||||
Neptune | Louisiana | 66% | 0.43 | 0.65 | ||||||||||||||||
Pascagoula | Mississippi | 40% | 0.40 | 1.50 | ||||||||||||||||
Thompsonville | Texas | 100% | 0.30 | 0.30 | ||||||||||||||||
Shoup | Texas | 100% | 0.29 | 0.29 | ||||||||||||||||
Gilmore | Texas | 100% | 0.26 | 0.26 | ||||||||||||||||
Armstrong | Texas | 100% | 0.25 | 0.25 | ||||||||||||||||
Matagorda | Texas | 100% | 0.25 | 0.25 | ||||||||||||||||
Others (10 facilities)(3) | Texas, New Mexico, Louisiana | Various(4) | 1.16 | 4.32 | ||||||||||||||||
Total processing capacities | 6.90 | 14.92 | ||||||||||||||||||
NGL fractionation facilities: | ||||||||||||||||||||
Mont Belvieu | Texas | 75% | 178 | 230 | ||||||||||||||||
Shoup and Armstrong | Texas | 100% | 87 | 87 | ||||||||||||||||
Norco | Louisiana | 100% | 75 | 75 | ||||||||||||||||
Promix | Louisiana | 50% | 73 | 145 | ||||||||||||||||
BRF | Louisiana | 32.2% | 19 | 60 | ||||||||||||||||
Tebone | Louisiana | 43.5% | 12 | 30 | ||||||||||||||||
Total plant capacities | 444 | 627 | ||||||||||||||||||
(1) | The approximate net natural gas processing and NGL fractionation capacity does not necessarily correspond to our ownership interest in each facility. It is based on a variety of factors such as volumes processed at the facility and ownership interest in the facility. | |
(2) | We acquired the Pioneer facility from TEPPCO in March 2006 and subsequently increased the processing capacity from 0.3 Bcf/d to 0.6 Bcf/d. | |
(3) | Includes our Venice, Blue Water, Sea Robin and Burns Point facilities located in Louisiana; Indian Basin and Carlsbad facilities located in New Mexico; and San Martin, Delmita, Sonora and Indian Springs facilities located in Texas. We acquired the Indians Springs facility in January 2005. Our ownership in the Venice plant is through our 13.1% equity method investment in VESCO. | |
(4) | Our ownership in these facilities ranges from 7.4% to 100%. |
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§ | OurMont BelvieuNGL fractionation facility is located at Mont Belvieu, Texas, which is a key hub of the domestic and international 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 Mountain Overthrust, East Texas and the Gulf Coast. | ||
§ | TheNorcoNGL fractionation facility 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 our Yscloskey, Pascagoula and Toca facilities. | ||
§ | ThePromixNGL fractionation facility receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast, including our Calumet, Neptune, Burns Point and Pascagoula facilities. In addition to the 362-mile Promix NGL Gathering System, Promix owns five NGL storage caverns and a barge loading facility that is integral to its operations. | ||
§ | OurShoupandArmstrongNGL fractionation facilities fractionate mixed NGLs supplied by our south Texas natural gas processing plants. The Shoup and Armstrong facilities supply NGLs transported by the DEP South Texas NGL Pipeline System. | ||
§ | TheBRFfacility processes mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana. |
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Approximate | ||||||||||||||||
Our | Capacity, | Gross | ||||||||||||||
Ownership | Length | Natural Gas | Capacity | |||||||||||||
Description of Asset | Location(s) | Interest | (Miles) | (MMcf/d) | (Bcf) | |||||||||||
Onshore natural gas pipelines: | ||||||||||||||||
Texas Intrastate System | Texas | 100% | 8,140 | 5,155 | ||||||||||||
Jonah Gathering System | Wyoming | 14.4%(1) | 643 | 1,750 | ||||||||||||
Piceance Creek Gathering System | Colorado | 100% | 48 | 1,600 | ||||||||||||
San Juan Gathering System | New Mexico, Colorado | 100% | 6,065 | 1,200 | ||||||||||||
Acadian Gas System | Louisiana | Various(2) | 1,042 | 954 | ||||||||||||
Permian Basin System | Texas, New Mexico | 100% | 1,387 | 490 | ||||||||||||
Alabama Intrastate System | Alabama | 100% | 408 | 200 | ||||||||||||
Encinal Gathering System | Texas | 100% | 452 | 143 | ||||||||||||
Other (5 systems)(3) | Texas, Mississippi | Various(4) | 704 | |||||||||||||
Total miles | 18,889 | |||||||||||||||
Natural gas storage facilities: | ||||||||||||||||
Petal | Mississippi | 100% | 11.9 | |||||||||||||
Hattiesburg | Mississippi | 100% | 4.0 | |||||||||||||
Wilson | Texas | Leased(5) | 6.4 | |||||||||||||
Acadian | Louisiana | Leased(6) | 3.0 | |||||||||||||
Total gross capacity | 25.3 | |||||||||||||||
(1) | Ownership interest as of December 31, 2006. This amount is expected to increase to approximately 20% upon completion of the Phase V expansion project. | |
(2) | Reflects consolidated ownership of Acadian Gas by the Operating Partnership (34%) and Duncan Energy Partners (66%). Also includes the 49.5% equity investment that Acadian Gas has in the Evangeline pipeline. | |
(3) | Includes the Delmita, Big Thicket, Indian Springs and Canales gathering systems located in Texas and the Petal pipeline located in Mississippi. The Delmita and Big Thicket gathering systems are integral parts of our natural gas processing operations, the results of operations and assets of which are accounted for under our NGL Pipelines & Services business segment. We acquired the Indian Springs gathering system in January 2005. We acquired the Canales gathering system in connection with the Encinal acquisition in July 2006. | |
(4) | We own 100% of these assets with the exception of the Indian Springs system, in which we own an 80% equity interest through a consolidated subsidiary. | |
(5) | This facility is held under an operating lease that expires in January 2028. | |
(6) | We hold this facility under an operating lease that expires in December 2012. |
§ | TheTexas Intrastate Systemgathers and transports natural gas from supply basins in Texas (from both onshore and offshore sources) to local gas distribution companies and electric generation and industrial and municipal consumers. This system serves important natural gas producing regions and commercial markets in Texas, including Corpus Christi, the San Antonio/Austin area, the Beaumont/Orange area, the Houston area, and the Houston Ship Channel industrial market. The Texas Intrastate System is comprised of the 7,292-mile Enterprise Texas Intrastate pipeline system, the 197-mile TPC Offshore gathering system and the 651-mile Channel pipeline system. The leased Wilson natural gas storage facility is an integral part of the Texas Intrastate System. We own 100% of the Texas Intrastate System with the exception of the Channel pipeline system, in which we own a 50% undivided interest. | ||
§ | TheJonah Gathering Systemis located in the Greater Green River Basin of southwestern Wyoming. This system gathers natural gas from the Jonah and Pinedale fields for delivery to regional natural gas processing plants, including our Pioneer facility, and major interstate pipelines. In August 2006, we entered into a joint venture with TEPPCO and are proceeding with |
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an expansion of the Jonah Gathering System. For additional information regarding this joint venture arrangement with TEPPCO and related expansion project, see Item 13 of this annual report. | |||
§ | ThePiceance Creek Gathering Systemconsists of a recently constructed natural gas gathering pipeline located in the Piceance Basin of northwestern Colorado. This pipeline is owned by Piceance Creek Pipeline, LLC, the ownership interests of which we acquired from EnCana Oil & Gas (“EnCana”) in December 2006. The Piceance Creek Gathering System extends from a connection with EnCana’s Great Divide Gathering System located near Parachute, Colorado, northward through the heart of the Piceance Basin to our 1.7 Bcf/d Meeker natural gas treating and processing complex, which is currently under construction. Connectivity to EnCana’s Great Divide Gathering System will provide the Piceance Creek Gathering System with access to natural gas production from the southern portion of the Piceance basin, including production from EnCana’s Mamm Creek field. The Piceance Creek Gathering System was placed in service in January 2007 and began transporting initial volumes of approximately 300 MMcf/d of natural gas. | ||
§ | TheSan Juan Gathering Systemserves natural gas producers in the San Juan Basin of New Mexico and Colorado. This system gathers natural gas production from over 10,400 wells in the San Juan Basin and delivers the natural gas to natural gas processing facilities, including our Chaco facility. | ||
§ | TheAcadian Gas Systempurchases, transports, stores and sells natural gas in Louisiana. The Acadian Gas System is comprised of the 577-mile Cypress pipeline, 438-mile Acadian pipeline and the 27-mile Evangeline pipeline. The leased Acadian natural gas storage facility is an integral part of the Acadian Gas System. | ||
We contributed a direct 66% equity interest in Acadian Gas, which is a subsidiary that owns the Cypress and Acadian pipelines, to Duncan Energy Partners on February 5, 2007. We own the remaining 34% direct interest in Acadian Gas. For additional information regarding this subsequent event, see “Recent Developments” within this Item 1. Acadian Gas owns a 49.5% indirect interest in the Evangeline pipeline. | |||
§ | ThePermian Basin Systemgathers natural gas from wells in the Permian Basin region of Texas and New Mexico and delivers natural gas into the El Paso Natural Gas, Transwestern and Oasis pipelines. The Permian Basin System is comprised of the 452-mile Waha system and 935-mile Carlsbad system. | ||
§ | TheAlabama Intrastate Systemmainly gathers coal bed methane from wells in the Black Warrior Basin in Alabama. This system is also involved in the purchase, transportation and sale of natural gas. | ||
§ | TheEncinal Gathering Systemgathers natural gas from the Olmos and Wilcox formations and delivers into our Texas Intrastate System, which delivers the natural gas into our south Texas facilities for processing. We acquired this gathering system in connection with the Encinal acquisition in July 2006. | ||
§ | OurPetalandHattiesburgunderground storage facilities are strategically situated to serve the domestic Northeast, Mid-Atlantic and Southeast natural gas markets and are capable of delivering in excess of 1.4 Bcf/d of natural gas into five interstate pipeline systems. |
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Our | Water | Approximate Net Capacity | ||||||||||||||||
Ownership | Length | Depth | Natural Gas | Crude Oil | ||||||||||||||
Description of Asset | Interest | (Miles) | (Feet) | (MMcf/d) | (MPBD) | |||||||||||||
Offshore natural gas pipelines: | ||||||||||||||||||
VESCO Gathering System | 13.1% | 260 | 800 | |||||||||||||||
Manta Ray Offshore Gathering System | 25.7% | 250 | 206 | |||||||||||||||
High Island Offshore System | 100% | 204 | 1,800 | |||||||||||||||
Viosca Knoll Gathering System | 100% | 164 | 1,000 | |||||||||||||||
Green Canyon Laterals | Various(1) | 136 | 649 | |||||||||||||||
Anaconda Gathering System(2) | 100% | 136 | 550 | |||||||||||||||
Independence Trail(3) | 100% | 134 | 1,000 | |||||||||||||||
Nautilus System | 25.7% | 101 | 154 | |||||||||||||||
East Breaks System | 100% | 85 | 400 | |||||||||||||||
Phoenix Gathering System | 100% | 78 | 450 | |||||||||||||||
Nemo Gathering System | 33.9% | 24 | 102 | |||||||||||||||
Falcon Natural Gas Pipeline | 100% | 14 | 400 | |||||||||||||||
Total miles | 1,586 | |||||||||||||||||
Offshore crude oil pipelines: | ||||||||||||||||||
Cameron Highway Oil Pipeline | 50% | 373 | 250 | |||||||||||||||
Poseidon Oil Pipeline System | 36% | 322 | 144 | |||||||||||||||
Constitution Oil Pipeline | 100% | 67 | 80 | |||||||||||||||
Allegheny Oil Pipeline | 100% | 43 | 140 | |||||||||||||||
Marco Polo Oil Pipeline | 100% | 37 | 120 | |||||||||||||||
Typhoon Oil Pipeline | 100% | 17 | 80 | |||||||||||||||
Tarantula Oil Pipeline | 100% | 4 | 30 | |||||||||||||||
Total miles | 863 | |||||||||||||||||
Offshore platforms: | ||||||||||||||||||
Independence Hub(3) | 80% | 8,000 | 1,000 | NA | ||||||||||||||
Marco Polo | 50% | 4,300 | 150 | 60 | ||||||||||||||
Viosca Knoll 817 | 100% | 671 | 140 | 5 | ||||||||||||||
Garden Banks 72 | 50% | 518 | 40 | 18 | ||||||||||||||
East Cameron 373 | 100% | 441 | 195 | 3 | ||||||||||||||
Falcon Nest | 100% | 389 | 400 | 3 |
(1) | Our ownership interests in the Green Canyon Laterals ranges from 2.7% to 100%. | |
(2) | Data shown for the Anaconda Gathering System includes the 30-mile Constitution natural gas pipeline, which we constructed and placed in-service in 2006. The Constitution natural gas pipeline has a net capacity of approximately 200 MMcf/d. | |
(3) | Construction of the Independence Trail pipeline and Independence Hub platform are substantially complete. The Independence Hub platform and Independence Trail pipeline are expected to begin operations during the second half of 2007. |
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§ | TheVESCO Gathering Systemis a 260-mile regulated natural gas pipeline system associated with the Venice natural gas processing plant in Louisiana. This pipeline is an integral part of the natural gas processing operations of VESCO. Our 13.1% interest in this system is held through our equity method investment in VESCO. | ||
§ | TheManta Ray Offshore Gathering Systemtransports 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 to numerous downstream pipelines, including our Nautilus System. Our ownership interest in this pipeline is held indirectly through our equity method investment in Neptune Pipeline Company, L.L.C. | ||
§ | TheHigh 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, Tennessee Gas Pipeline and the U-T Offshore System. The HIOS pipeline system includes 10 pipeline junction and service platforms. | ||
§ | TheViosca Knoll Gathering Systemtransports natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas to several major interstate pipelines, including the Tennessee Gas, Columbia Gulf, Southern Natural, Transco, Dauphin Island Gathering System and Destin Pipelines. | ||
§ | TheGreen Canyon Lateralsconsist of 28 pipeline laterals (which are extensions of natural gas pipelines) that transport natural gas to downstream pipelines, including the HIOS. | ||
§ | TheAnaconda Gathering Systemconnects our Marco Polo platform and the third-party owned Constitution platform to the ANR pipeline system. The Anaconda Gathering System includes our wholly-owned Typhoon, Marco Polo and Constitution natural gas pipelines. The Constitution natural gas pipeline was completed in late 2005 and serves the Constitution and Ticonderoga fields located in the central Gulf of Mexico. We initiated flows into our Constitution natural gas pipeline during the first quarter of 2006. | ||
§ | TheIndependence Trailnatural gas pipeline will transport natural gas from our Independence Hub platform to the Tennessee Gas Pipeline. Natural gas transported on the Independence Trail will come from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. This pipeline includes one pipeline junction platform at West Delta 68. We completed construction of the Independence Trail natural gas pipeline during 2006, with an expected in-service date during the second half of 2007. | ||
§ | TheNautilus Systemconnects our Manta Ray Offshore Gathering System to our Neptune natural gas processing plant on the Louisiana gulf coast. Our ownership interest in this pipeline is held indirectly through our equity method investment in Neptune Pipeline Company, L.L.C. | ||
§ | TheEast Breaks Systemconnects the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25 to the HIOS pipeline system. | ||
§ | ThePhoenix Gathering Systemconnects the Red Hawk platform located in the Garden Banks area of the Gulf of Mexico to the ANR pipeline system. | ||
§ | TheNemo Gathering Systemtransports natural gas from Green Canyon developments to an interconnect with our Manta Ray Offshore Gathering System. Our ownership interest in this pipeline is held indirectly through our equity method investment in Nemo Gathering Company, LLC. |
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§ | TheFalcon Natural Gas Pipelinedelivers natural gas processed at our Falcon Nest platform to a connection with the Central Texas Gathering System located on the Brazos Addition Block 133 platform. |
§ | TheCameron Highway Oil Pipeline, which commenced operations during the first quarter of 2005, gathers crude oil production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas. This pipeline includes one pipeline junction platform. Our 50% joint control ownership interest in this pipeline is held indirectly through our equity method investment in Cameron Highway Oil Pipeline Company (“Cameron Highway”). | ||
§ | ThePoseidon Oil Pipeline Systemgathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana. This system includes one pipeline junction platform. Our ownership interest in this pipeline is held indirectly through our equity method investment in Poseidon Oil Pipeline Company, LLC. | ||
§ | TheConstitution Oil Pipelinewas completed in late 2005 and serves the Constitution and Ticonderoga fields located in the central Gulf of Mexico. Initial throughput volumes were received during the first quarter of 2006. The Constitution Oil Pipeline connects with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at a pipeline junction platform. | ||
§ | TheAllegheny Oil Pipelineconnects 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. | ||
§ | TheMarco Polo Oil Pipelinetransports crude oil from our Marco Polo platform to an interconnect with our Allegheny Oil Pipeline in Green Canyon Block 164. |
§ | TheIndependence Hubplatform is located in Mississippi Canyon Block 920. This platform will process crude oil and natural gas gathered from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. We expect to complete construction of the Independence Hub platform in March 2007, with an expected in-service date during the second half of 2007. | ||
§ | TheMarco Poloplatform, which is located in Green Canyon Block 608, processes crude oil and natural gas from the Marco Polo, K2, and K2 North fields and should begin processing production from the Genghis Khan field in the second quarter of 2007. These fields are located in the South |
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Green Canyon area of the Gulf of Mexico. Our 50% joint control ownership interest in this platform is held indirectly through our equity method investment in Deepwater Gateway LLC. | |||
§ | TheViosca Knoll 817platform is centrally located on our Viosca Knoll Gathering System. This platform primarily serves as a base for gathering deepwater production in the area, including the Ram Powell development. | ||
§ | TheGarden Banks 72platform serves as a base for gathering deepwater production from the Garden Banks Block 161 development and the Garden Banks Block 378 and 158 leases. This platform also serves as a junction platform for our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System. | ||
§ | TheEast Cameron 373platform serves as the host for East Cameron Block 373 production and also processes production from Garden Banks Blocks 108, 152, 197, 200 and 201. | ||
§ | TheFalcon Nestplatform currently processes natural gas from the Falcon field. |
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Net | Total | |||||||||||||||
Our | Plant | Plant | ||||||||||||||
Ownership | Capacity | Capacity | Length | |||||||||||||
Description of Asset | Location(s) | Interest | (MBPD) | (MBPD) | (Miles) | |||||||||||
Propylene fractionation facilities: | ||||||||||||||||
Mont Belvieu (3 plants) | Texas | Various(1) | 58 | 72 | ||||||||||||
BRPC | Louisiana | 30%(2) | 7 | 23 | ||||||||||||
Total capacity | 65 | 95 | ||||||||||||||
Isomerization facility: | ||||||||||||||||
Mont Belvieu(3) | Texas | 100% | 116 | 116 | ||||||||||||
Petrochemical pipelines: | ||||||||||||||||
Lou-Tex and Sabine Propylene | Texas, Louisiana | 100%(4) | 284 | |||||||||||||
Texas City RGP Gathering System | Texas | 100% | 108 | |||||||||||||
Lake Charles | Texas, Louisiana | 50% | 83 | |||||||||||||
Others (6 systems)(5) | Texas, Louisiana | Various(6) | 204 | |||||||||||||
Total miles | 679 | |||||||||||||||
Octane additive production facilities: | ||||||||||||||||
Mont Belvieu | Texas | 100% | 12 | 12 |
(1) | We own a 54.6% interest and lease the remaining 45.4% of a facility having 17 MBPD of plant capacity. We own a 66.7% interest in a second facility having 41 MBPD of total plant capacity. We own 100% of the remaining facility, which has 14 MBPD of plant capacity. | |
(2) | Our ownership interest in this facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC (“BRPC”). | |
(3) | On a weighted-average basis, utilization rates for this facility were approximately 70% during each of 2006 and 2005 and 66% during 2004. | |
(4) | Reflects consolidated ownership of these pipelines by the Operating Partnership (34%) and Duncan Energy Partners (66%). | |
(5) | Includes our Texas City PGP Gathering System and Port Neches, Bay Area, La Porte, Port Arthur and Bayport petrochemical pipelines. | |
(6) | We own 100% of these pipelines with the exception of the 17-mile La Porte pipeline, in which we hold an aggregate 50% indirect interest through our equity method investments in La Porte Pipeline Company L.P. and La Porte Pipeline GP, L.L.C. |
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§ | the level of domestic production; | ||
§ | the availability of imported oil and natural gas; | ||
§ | actions taken by foreign oil and natural gas producing nations; | ||
§ | the availability of transportation systems with adequate capacity; | ||
§ | the availability of competitive fuels; | ||
§ | fluctuating and seasonal demand for oil, natural gas and NGLs; |
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§ | the impact of conservation efforts; | ||
§ | the extent of governmental regulation and taxation of production; and | ||
§ | the overall economic environment. |
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§ | geographic proximity to the production; | ||
§ | costs of connection; | ||
§ | available capacity; | ||
§ | rates; and | ||
§ | access to markets. |
§ | a substantial portion of our cash flow, including that of Duncan Energy Partners, 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 view our debt level negatively; | ||
§ | covenants contained in our existing and future credit and debt arrangements 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; |
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§ | 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. |
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§ | difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments; | ||
§ | establishing the internal controls and procedures that 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; | ||
§ | 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. |
§ | mistaken assumptions about volumes, revenues and costs, including synergies; | ||
§ | an inability to integrate successfully the businesses we acquire; | ||
§ | decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition; |
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§ | a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition; | ||
§ | the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate; | ||
§ | an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; | ||
§ | limitations on rights to indemnity from the seller; | ||
§ | mistaken assumptions about the overall costs of equity or debt; | ||
§ | the diversion of management’s and employees’ attention from other business concerns; | ||
§ | unforeseen difficulties operating in new product areas or new geographic areas; and | ||
§ | customer or key employee losses at the acquired businesses. |
§ | 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; |
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§ | we will not receive any material increases in revenues 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 growth in production 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; | ||
§ | where we do rely on third-party estimates of reserves in making a decision to construct facilities, these estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating reserves; and | ||
§ | we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical. |
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§ | the proportionate ownership interest of a common unit will decrease; | ||
§ | the amount of cash available for distributions on each common unit may decrease; | ||
§ | the ratio of taxable income to distributions may increase; |
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§ | the relative voting strength of each previously outstanding common unit may be diminished; and | ||
§ | the market price of our common units may decline. |
§ | the level of our operating costs; | ||
§ | the level of competition in our business segments; | ||
§ | prevailing economic conditions; | ||
§ | the level of capital expenditures we make; | ||
§ | the restrictions contained in our debt agreements and our debt service requirements; | ||
§ | fluctuations in our working capital needs; | ||
§ | the cost of acquisitions, if any; and | ||
§ | the amount, if any, of cash reserves established by Enterprise Products GP in its sole discretion. |
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§ | neither our partnership agreement nor any other agreement requires Enterprise Products GP or EPCO to pursue a business strategy that favors us; | ||
§ | decisions of Enterprise Products GP regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units and reserves in any quarter may affect the level of cash available to pay quarterly distributions to unitholders and Enterprise Products GP; | ||
§ | under our partnership agreement, Enterprise Products GP determines which costs incurred by it and its affiliates are reimbursable by us; | ||
§ | Enterprise Products GP is allowed to resolve any conflicts of interest involving us and Enterprise Products GP and its affiliates; | ||
§ | Enterprise Products GP is allowed to 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 unitholders; | ||
§ | any resolution of a conflict of interest by Enterprise Products GP not made in bad faith and that is fair and reasonable to us shall be binding on the partners and shall not be a breach of our partnership agreement; | ||
§ | affiliates of Enterprise Products GP, including TEPPCO, may compete with us in certain circumstances; | ||
§ | Enterprise Products GP 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, Enterprise Products GP may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions; | ||
§ | our partnership agreement does not restrict Enterprise Products GP from causing 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; |
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§ | Enterprise Products GP intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us; | ||
§ | Enterprise Products GP controls the enforcement of obligations owed to us by our general partner and its affiliates; and | ||
§ | Enterprise Products GP decides whether to retain separate counsel, accountants or others to perform services for us. |
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§ | we were conducting business in a state, but had not complied with that particular state’s partnership statute; or | ||
§ | your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business. |
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Cash Distribution History | ||||||||||||||||||||
Price Ranges | Per | Record | Payment | |||||||||||||||||
High | Low | Unit | Date | Date | ||||||||||||||||
2005 | ||||||||||||||||||||
1st Quarter | $ | 28.350 | $ | 23.920 | $ | 0.4100 | Apr. 29, 2005 | May 10, 2005 | ||||||||||||
2nd Quarter | $ | 27.090 | $ | 24.770 | $ | 0.4200 | Jul. 29, 2005 | Aug. 10, 2005 | ||||||||||||
3rd Quarter | $ | 27.660 | $ | 23.500 | $ | 0.4300 | Oct. 31, 2005 | Nov. 8, 2005 | ||||||||||||
4th Quarter | $ | 26.020 | $ | 23.380 | $ | 0.4375 | Jan. 31, 2006 | Feb. 9, 2006 | ||||||||||||
2006 | ||||||||||||||||||||
1st Quarter | $ | 26.000 | $ | 23.690 | $ | 0.4450 | Apr. 28, 2006 | May 10, 2006 | ||||||||||||
2nd Quarter | $ | 25.710 | $ | 23.760 | $ | 0.4525 | Jul. 31, 2006 | Aug. 10, 2006 | ||||||||||||
3rd Quarter | $ | 27.060 | $ | 25.000 | $ | 0.4600 | Oct. 31, 2006 | Nov. 8, 2006 | ||||||||||||
4th Quarter | $ | 29.980 | $ | 26.050 | $ | 0.4675 | Jan. 31, 2007 | Feb. 8, 2007 |
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For the Year Ended December 31, | ||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Operating results data:(1) | ||||||||||||||||||||
Revenues | $ | 13,990,969 | $ | 12,256,959 | $ | 8,321,202 | $ | 5,346,431 | $ | 3,584,783 | ||||||||||
Income from continuing operations(2) | $ | 599,683 | $ | 423,716 | $ | 257,480 | $ | 104,546 | $ | 95,500 | ||||||||||
Income per unit from continuing operations: | ||||||||||||||||||||
Basic | $ | 1.22 | $ | 0.92 | $ | 0.83 | $ | 0.42 | $ | 0.55 | ||||||||||
Diluted | $ | 1.22 | $ | 0.92 | $ | 0.83 | $ | 0.41 | $ | 0.48 | ||||||||||
Other financial data: | ||||||||||||||||||||
Distributions per common unit(3) | $ | 1.825 | $ | 1.698 | $ | 1.540 | $ | 1.470 | $ | 1.360 | ||||||||||
Commodity hedging income (loss)(4) | $ | 10,257 | $ | 1,095 | $ | 448 | $ | (619 | ) | $ | (51,344 | ) |
As of December 31, | ||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Financial position data:(1) | ||||||||||||||||||||
Total assets | $ | 13,989,718 | $ | 12,591,016 | $ | 11,315,461 | $ | 4,802,814 | $ | 4,230,272 | ||||||||||
Long-term and current maturities of debt(5) | $ | 5,295,590 | $ | 4,833,781 | $ | 4,281,236 | $ | 2,139,548 | $ | 2,246,463 | ||||||||||
Partners’ equity(6) | $ | 6,480,233 | $ | 5,679,309 | $ | 5,328,785 | $ | 1,705,953 | $ | 1,200,904 | ||||||||||
Total units outstanding (excluding treasury)(6) | 432,408 | 389,861 | 364,786 | 217,780 | 183,810 |
(1) | In general, our historical operating results and financial position have been affected by numerous acquisitions since 2001. Our most significant transaction to date was the GulfTerra Merger, which was completed on September 30, 2004. The aggregate value of the total consideration we paid or issued to complete the GulfTerra Merger was approximately $4 billion. We accounted for the GulfTerra Merger and our other acquisitions using purchase accounting; therefore, the operating results of these acquired entities are included in our financial results prospectively from their respective acquisition dates. For additional information regarding such transactions, see Note 12 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. | |
(2) | Amounts presented for the years ended December 31, 2006, 2005 and 2004 are before the cumulative effect of accounting changes. | |
(3) | Distributions per common unit represent declared cash distributions with respect to the four fiscal quarters of each period presented. | |
(4) | Income from continuing operations includes our gain or loss from commodity hedging activities. A variety of factors influence whether or not a particular hedging strategy is successful. As a result of incurring significant losses from commodity hedging transactions in early 2002 due to a rapid increase in natural gas prices, we exited those commodity hedging strategies that created the losses. Since that time, we have utilized only a limited number of commodity financial instruments. For additional information regarding our use of financial instruments, see Item 7A of this annual report. (5) In general, the balances of our long-term and current maturities of debt have increased over time as a result of financing all or a portion of acquisitions and other capital spending. | |
(6) | We regularly issue common units through underwritten public offerings and, less frequently, in connection with acquisitions or other transactions. The increase in partners’ equity since 2002 has been the result of such transactions, with the September 2004 issuance of 104.5 million common units in connection with the GulfTerra Merger being our largest. For additional information regarding our partners’ equity and unit history, see Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. |
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• | Overview of Business. | ||
• | Results of Operations – Discusses material year-to-year variances in our Consolidated Statements of Operations. | ||
• | Liquidity and Capital Resources – Addresses available sources of liquidity and analyzes cash flows. | ||
• | Critical Accounting Policies – Presents accounting policies that are among the most significant to the portrayal of our financial condition and results of operations. | ||
• | Other Items – Includes information related to contractual obligations, off-balance sheet arrangements, related party transactions, recent accounting pronouncements and similar disclosures. |
/ d | = | per day | ||||
BBtus | = | billion British thermal units | ||||
Bcf | = | billion cubic feet | ||||
MBPD | = | thousand barrels per day | ||||
Mdth | = | thousand decatherms | ||||
MMBbls | = | million barrels | ||||
MMBtus | = | million British thermal units | ||||
MMcf | = | million cubic feet | ||||
Mcf | = | thousand cubic feet | ||||
TBtu | = | trillion British thermal units |
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• | In February 2007, Duncan Energy Partners L.P. (“Duncan Energy Partners”), a consolidated subsidiary of ours, completed an underwritten initial public offering of 14,950,000 of its common units. We formed Duncan Energy Partners as a Delaware limited partnership to acquire ownership interests in certain of our midstream energy businesses. For additional information regarding Duncan Energy Partners, see “Other Items – Initial Public Offering of Duncan Energy Partners” included within this Item 7. | ||
• | In December 2006, we purchased all of the membership interests in Piceance Creek Pipeline, LLC (“Piceance Creek Pipeline”) from an affiliate of the EnCana Corporation (“EnCana”) for $100 million. The assets of Piceance Creek Pipeline consist primarily of a recently constructed 48-mile natural gas gathering pipeline (the “Piceance Creek Gathering System”) located in the Piceance Basin of northwest Colorado. This pipeline will connect to our Meeker natural gas processing plant, which is currently under construction. | ||
• | In December 2006, Standard & Poor’s raised its credit rating of our Operating Partnership from BB+ to BBB-, which is investment grade, with a stable outlook. As a result of this change, all of the senior unsecured credit ratings of our Operating Partnership are currently at an investment grade level. | ||
• | In November 2006, we entered into a 30-year agreement with an affiliate of Exxon Mobil Corporation (“ExxonMobil”), to provide gathering, compression, treating and conditioning services for natural gas produced as part of a development program planned by ExxonMobil in the Piceance Basin in Colorado. Under the terms of the agreement, ExxonMobil’s natural gas production from its Piceance Development Project, which encompasses more than 29,000 acres in Rio Blanco County, Colorado, will be dedicated to us. The fee-based agreement |
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includes an option for us to recover NGLs beyond those extracted to condition the gas to meet downstream pipeline specifications. | |||
To provide these services, we expect to invest approximately $185 million to construct new plant and pipeline facilities to compress the natural gas, treat it to remove impurities, extract NGLs, and deliver gas to the various pipeline transmission systems that serve the region. Construction of the facilities will begin after the receipt of the necessary permits and approvals and is expected to be completed in late 2008. | |||
• | In November 2006, we announced an expansion of our Texas Intrastate Pipeline with the construction of a 178-mile pipeline (the “Sherman Extension”) that will transport up to 1.1 Bcf/d of natural gas from the growing Barnett Shale area of North Texas. This new pipeline is expected to cost $424.6 million, most of which will be spent in 2008, and be placed in service during the fourth quarter of 2008. | ||
• | In October 2006, we signed definitive agreements with producers to construct, own and operate an offshore oil pipeline that will provide firm gathering services from the Shenzi production field located in the Southern Green Canyon area of the central Gulf of Mexico. | ||
• | In September 2006, we sold 12,650,000 of our common units in an underwritten public offering, which generated net proceeds of approximately $320.8 million. | ||
• | During the third quarter of 2006, the Operating Partnership sold $550 million in principal amount of fixed/floating unsecured junior subordinated notes due 2066 (the “Junior Subordinated Notes A”). For additional information regarding this issuance of debt, see “Liquidity and Capital Resources – Debt Obligations” included within this Item 7. | ||
• | In August 2006, we became a joint venture partner with TEPPCO involving its Jonah Gas Gathering Company (“Jonah”). Jonah owns the Jonah Gathering System, located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants, including our Pioneer plant, and major interstate pipelines that deliver natural gas to end-use markets. As part of this new joint venture, we and TEPPCO are significantly expanding the Jonah Gathering System (the Phase V expansion project). | ||
• | In August 2006, we purchased a 220-mile NGL pipeline extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for this asset was $97.7 million in cash. This pipeline (in combination with others to be constructed or acquired) will be used to transport NGLs from our South Texas natural gas processing plants to our Mont Belvieu fractionation facilities. Duncan Energy Partners acquired an indirect 66% interest in this pipeline asset on February 5, 2007. | ||
• | In August 2006, our wholly owned subsidiary, Mid-America Pipeline Company LLC (“Mid-America”), executed new long-term transportation agreements with all but one of its current shippers on its Rocky Mountain pipeline pursuant to terms and conditions of Mid-America’s open season tariff that was accepted by the Federal Energy Regulatory Commission effective August 6, 2006. Under the terms of the new agreements, shippers have committed to transport all of their current and future NGL production from the Rocky Mountains through the Mid-America Pipeline System to either our Hobbs fractionator (expected to be operational by mid-2007) or to Mont Belvieu, Texas via our Seminole Pipeline for a minimum of 10 years and up to a maximum of 20 years. Based on shipper production forecasts and current NGL extraction rates, we expect that these new agreements will fully utilize our Mid-America Pipeline System, including the 50 MBPD Phase I Expansion expected to be placed in-service during the third quarter of 2007. | ||
• | In July 2006, we signed long-term agreements with CenterPoint Energy Resources Corp. (“CenterPoint Energy”) to provide firm natural gas transportation and storage services to its |
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natural gas utility, primarily in the Houston, Texas metropolitan area. We will provide CenterPoint Energy with an estimated 14 Bcf per year of natural gas beginning in April 2007. Our deliveries to CenterPoint Energy through these new contracts will mark the first time that we have had the opportunity to serve the growing Houston area natural gas market. We are already the primary natural gas service provider to the San Antonio and Austin, Texas markets. | |||
• | In July 2006, we acquired the Encinal and Canales natural gas gathering systems and their related gathering and processing contracts and other amounts that comprised the South Texas natural gas transportation and processing business of Cerrito Gathering Company, Ltd., an affiliate of Lewis Energy Group, L.P. (“Lewis”). The aggregate value of total consideration we paid or issued to complete this business combination (referred to as the “Encinal acquisition”) was $326.3 million, which includes $145.2 million in cash paid to Lewis and the issuance of 7,115,844 of our common units to Lewis. | ||
• | In April 2006, we announced plans to expand our Houston Ship Channel NGL import and export facility and related pipeline and other assets to accommodate an expected increase in throughput volumes. | ||
• | In March 2006, we purchased the Pioneer natural gas processing plant and certain related natural gas processing rights from TEPPCO for $38.2 million in cash. | ||
• | In March 2006, we announced plans to expand our petrochemical assets located in southeast Texas. The plans include the construction of a new propylene fractionator at our Mont Belvieu, Texas facility and the expansion of two refinery grade propylene pipelines. | ||
• | In March 2006, we sold 18,400,000 of our common units in a public offering, which generated net proceeds of approximately $430 million. | ||
• | In January 2006, we announced the execution of a minimum 15-year natural gas processing agreement with an affiliate of EnCana. Under this agreement, we have the right to process up to 1.3 Bcf/d of EnCana’s natural gas production from the Piceance Basin area of western Colorado. To accommodate this production, we began construction of the Meeker natural gas processing facility in Rio Blanco County, Colorado. In addition, we will construct a 50-mile NGL pipeline that will connect our Meeker processing facility to our Mid-America Pipeline System. |
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Capital spending for business combinations and asset purchases: | ||||||||||||
GulfTerra Merger: | ||||||||||||
Cash payments to El Paso, including amounts paid to acquire certain South Texas midstream assets | $ | 655,277 | ||||||||||
Transaction fees and other direct costs | 24,032 | |||||||||||
Cash received from GulfTerra | (40,313 | ) | ||||||||||
Net cash payments | 638,996 | |||||||||||
Value of non-cash consideration issued or granted | 2,910,771 | |||||||||||
Total GulfTerra Merger consideration | 3,549,767 | |||||||||||
Encinal acquisition, including non-cash equity consideration | $ | 326,309 | $ | — | — | |||||||
Piceance Creek acquisition | 100,000 | — | — | |||||||||
NGL underground storage and terminalling assets purchased from Ferrellgas | — | 145,522 | — | |||||||||
Indirect interests in the Indian Springs natural gas gathering and processing assets | — | 74,854 | — | |||||||||
Additional ownership interests in Dixie Pipeline Company (“Dixie”) | 12,913 | 68,608 | — | |||||||||
Additional ownership interests in Mid-America and Seminole pipeline systems | — | 25,000 | — | |||||||||
Other business combinations and asset purchases | 18,390 | 12,618 | 85,851 | |||||||||
Total | 457,612 | 326,602 | 3,635,618 | |||||||||
Capital spending for property, plant and equipment: | ||||||||||||
Growth capital projects, net | 1,148,123 | 719,372 | 113,759 | |||||||||
Sustaining capital projects | 132,455 | 98,077 | 33,169 | |||||||||
Total | 1,280,578 | 817,449 | 146,928 | |||||||||
Capital spending attributable to unconsolidated affiliates: | ||||||||||||
Investment in and advances to Jonah Gas Gathering Company | 120,132 | |||||||||||
Other investments in and advances to unconsolidated affiliates | 7,290 | 88,044 | 64,412 | |||||||||
Total | 127,422 | 88,044 | 64,412 | |||||||||
Total capital spending | $ | 1,865,612 | $ | 1,232,095 | $ | 3,846,958 | ||||||
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Cash payment to Lewis | $ | 145,197 | ||
Fair value of our 7,115,844 common units issued to Lewis | 181,112 | |||
Total consideration | $ | 326,309 | ||
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Polymer | Refinery | |||||||||||||||||||||||||||||||||||
Natural | Normal | Natural | Grade | Grade | ||||||||||||||||||||||||||||||||
Gas, | Crude Oil, | Ethane, | Propane, | Butane, | Isobutane, | Gasoline, | Propylene, | Propylene, | ||||||||||||||||||||||||||||
$/MMBtu | $/barrel | $/gallon | $/gallon | $/gallon | $/gallon | $/gallon | $/pound | $/pound | ||||||||||||||||||||||||||||
(1) | (2) | (1) | (1) | (1) | (1) | (1) | (1) | (1) | ||||||||||||||||||||||||||||
2004 Averages | $ | 6.13 | $ | 41.45 | $ | 0.50 | $ | 0.74 | $ | 0.88 | $ | 0.88 | $ | 1.00 | $ | 0.33 | $ | 0.29 | ||||||||||||||||||
2005 Averages | $ | 8.64 | $ | 56.47 | $ | 0.62 | $ | 0.91 | $ | 1.09 | $ | 1.15 | $ | 1.26 | $ | 0.42 | $ | 0.37 | ||||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||
1st Quarter | $ | 9.01 | $ | 63.35 | $ | 0.57 | $ | 0.94 | $ | 1.20 | $ | 1.27 | $ | 1.38 | $ | 0.45 | $ | 0.40 | ||||||||||||||||||
2nd Quarter | $ | 6.80 | $ | 70.53 | $ | 0.68 | $ | 1.05 | $ | 1.22 | $ | 1.26 | $ | 1.52 | $ | 0.50 | $ | 0.44 | ||||||||||||||||||
3rd Quarter | $ | 6.58 | $ | 70.44 | $ | 0.76 | $ | 1.10 | $ | 1.28 | $ | 1.30 | $ | 1.53 | $ | 0.51 | $ | 0.46 | ||||||||||||||||||
4th Quarter | $ | 6.56 | $ | 60.03 | $ | 0.62 | $ | 0.95 | $ | 1.11 | $ | 1.12 | $ | 1.31 | $ | 0.44 | $ | 0.35 | ||||||||||||||||||
2006 Averages | $ | 7.24 | $ | 66.09 | $ | 0.66 | $ | 1.01 | $ | 1.20 | $ | 1.24 | $ | 1.44 | $ | 0.47 | $ | 0.41 | ||||||||||||||||||
(1) | Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including Oil Price Information Service (“OPIS”) and Chemical Market Associates, Inc. (“CMAI”). Natural gas price is representative of Henry-Hub I-FERC. NGL prices are representative of Mont Belvieu Non-TET pricing. Refinery grade propylene represents an average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing. | |
(2) | Crude oil price is representative of an index price for West Texas Intermediate. |
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
NGL Pipelines & Services, net: | ||||||||||||
NGL transportation volumes (MBPD) | 1,577 | 1,478 | 1,411 | |||||||||
NGL fractionation volumes (MBPD) | 312 | 292 | 307 | |||||||||
Equity NGL production (MBPD)(1) | 63 | 68 | 76 | |||||||||
Fee-based natural gas processing (MMcf/d) | 2,218 | 1,767 | 1,692 | |||||||||
Onshore Natural Gas Pipelines & Services, net: | ||||||||||||
Natural gas transportation volumes (BBtus/d) | 6,012 | 5,916 | 5,638 | |||||||||
Offshore Pipelines & Services, net: | ||||||||||||
Natural gas transportation volumes (BBtus/d) | 1,520 | 1,780 | 2,081 | |||||||||
Crude oil transportation volumes (MBPD) | 153 | 127 | 138 | |||||||||
Platform gas processing (BBtus/d) | 159 | 252 | 306 | |||||||||
Platform oil processing (MBPD) | 15 | 7 | 14 | |||||||||
Petrochemical Services, net: | ||||||||||||
Butane isomerization volumes (MBPD) | 81 | 81 | 76 | |||||||||
Propylene fractionation volumes (MBPD) | 56 | 55 | 57 | |||||||||
Octane additive production volumes (MBPD) | 9 | 6 | 10 | |||||||||
Petrochemical transportation volumes (MBPD) | 97 | 64 | 71 | |||||||||
Total, net: | ||||||||||||
NGL, crude oil and petrochemical transportation volumes (MBPD) | 1,827 | 1,669 | 1,620 | |||||||||
Natural gas transportation volumes (BBtus/d) | 7,532 | 7,696 | 7,719 | |||||||||
Equivalent transportation volumes (MBPD)(2) | 3,809 | 3,694 | 3,651 |
(1) | Volumes for 2005 and 2004 have been revised to incorporate asset-level definitions of equity NGL production volumes. | |
(2) | Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs. |
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Revenues | $ | 13,990,969 | $ | 12,256,959 | $ | 8,321,202 | ||||||
Operating costs and expenses | 13,089,091 | 11,546,225 | 7,904,336 | |||||||||
General and administrative costs | 63,391 | 62,266 | 46,659 | |||||||||
Equity in income of unconsolidated affiliates | 21,565 | 14,548 | 52,787 | |||||||||
Operating income | 860,052 | 663,016 | 422,994 | |||||||||
Interest expense | 238,023 | 230,549 | 155,740 | |||||||||
Net income | 601,155 | 419,508 | 268,261 |
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Gross operating margin by segment: | ||||||||||||
NGL Pipelines & Services | $ | 752,548 | $ | 579,706 | $ | 374,196 | ||||||
Onshore Natural Gas Pipelines & Services | 333,399 | 353,076 | 90,977 | |||||||||
Offshore Pipeline & Services | 103,407 | 77,505 | 36,478 | |||||||||
Petrochemical Services | 173,095 | 126,060 | 121,515 | |||||||||
Other, non-segment | — | — | 32,025 | |||||||||
Total segment gross operating margin | $ | 1,362,449 | $ | 1,136,347 | $ | 655,191 | ||||||
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
NGL Pipelines & Services: | ||||||||||||
Sale of NGL products | $ | 9,496,926 | $ | 8,176,370 | $ | 5,542,877 | ||||||
Percent of consolidated revenues | 68 | % | 67 | % | 67 | % | ||||||
Onshore Natural Gas Pipelines & Services: | ||||||||||||
Sale of natural gas | $ | 1,230,369 | $ | 1,065,542 | $ | 686,770 | ||||||
Percent of consolidated revenues | 9 | % | 9 | % | 8 | % | ||||||
Petrochemical Services: | ||||||||||||
Sale of petrochemical products | $ | 1,545,693 | $ | 1,311,956 | $ | 1,054,994 | ||||||
Percent of consolidated revenues | 11 | % | 11 | % | 13 | % |
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Business interruption proceeds: | ||||
Hurricane Ivan | $ | 17,382 | ||
Hurricane Katrina | 24,500 | |||
Hurricane Rita | 22,000 | |||
Total proceeds | $ | 63,882 | ||
Property damage proceeds: | ||||
Hurricane Ivan | $ | 24,104 | ||
Hurricane Katrina | 7,500 | |||
Hurricane Rita | 3,000 | |||
Total proceeds | $ | 34,604 | ||
Total proceeds received during 2006 | $ | 98,486 | ||
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• | We believe that drilling activity in the major producing areas where we operate, including the Gulf of Mexico and supply basins in Texas, San Juan and the Rocky Mountains, will result in increased demand for our midstream energy services. As a result, we expect higher transportation and processing volumes for our existing assets due to increased natural gas and crude oil production from both onshore and offshore producing areas. In addition, we expect to benefit from increased demand as new assets come on-line during 2007. | ||
• | We expect to benefit from an increase in crude oil and natural gas production in the Gulf of Mexico as our Independence Hub platform and Independence Trail pipeline are placed in-service during the second half of 2007. Our Independence Hub platform and Independence Trail pipeline will benefit from initial natural gas production from dedicated production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. In addition, we believe that our Marco Polo Oil Pipeline and Marco Polo platform will continue to benefit as production volumes increase from developments in the Southern Green Canyon area of the Gulf of Mexico. Increased production in the Gulf of Mexico will increase volumes of natural gas and NGLs available to our facilities in southern Louisiana. | ||
• | We expect the volume of natural gas and NGLs available to our facilities in Texas to increase as a result of drilling activity and long-term agreements executed with new customers. We expect natural gas transportation volumes on our Texas Intrastate System to increase during 2007 as we begin to supply the Houston, Texas area with natural gas volumes under a long-term agreement with CenterPoint Energy. As a result of the Encinal acquisition, we expect to increase natural gas gathering and processing volumes in south Texas. In turn, this should increase our NGL production in south Texas. In addition, we will continue to expand our natural gas gathering assets in the Barnett shale region of north Texas. | ||
• | We expect to benefit from increased natural gas and NGL volumes as several new assets are placed in-service throughout Wyoming, Colorado and New Mexico. We expect our new Pioneer natural gas processing plant and expanded Jonah Gathering System to benefit from increased production in the Greater Green River basin of Wyoming. Production from the Piceance basin of western Colorado should benefit our Piceance Creek Gathering System and Meeker natural gas processing plant. We expect our Mid-America Pipeline System, Seminole Pipeline and Hobbs NGL fractionator to benefit from increased volumes of NGLs produced at the Pioneer and Meeker natural gas processing facilities. | ||
• | We believe that the strength of the domestic and global economy will continue to drive increased demand for all forms of energy despite fluctuating commodity prices. Our largest NGL consuming customers in the ethylene industry continue to see strong demand for their products. Ethane and propane continue to be the preferred feedstocks for the ethylene industry with the high price of crude oil relative to natural gas. |
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• | In March 2006, we sold 18,400,000 common units (including an over-allotment amount of 2,400,000 common units) to the public at an offering price of $23.90 per unit. Net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution of $8.6 million, were approximately $430 million after deducting applicable underwriting discounts, commissions and estimated offering expenses of $18.3 million. The net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution, were used to temporarily reduce indebtedness outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility. | ||
• | In July 2006, we issued approximately 7.1 million of our common units in connection with the Encinal business acquisition. In August 2006, we filed a registration statement with the SEC for the resale of these common units. | ||
• | In September 2006, we sold 12,650,000 common units (including an over-allotment amount of 1,650,000 common units) to the public at an offering price of $25.80 per unit. Net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution of $6.4 |
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million, were approximately $320.8 million after deducting applicable underwriting discounts, commissions and estimated offering expenses of $11.8 million. Net proceeds of $260 million from this offering, including Enterprise Products GP’s proportionate net capital contribution, were used to temporarily reduce indebtedness outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility. The remaining net proceeds were used for general partnership purposes. |
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At December 31, | ||||||||
2006 | 2005 | |||||||
Operating Partnership senior debt obligations: | ||||||||
Multi-Year Revolving Credit Facility, variable rate, due October 2011(1) | $ | 410,000 | $ | 490,000 | ||||
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 | 54,000 | 54,000 | ||||||
Senior Notes B, 7.50% fixed-rate, due February 2011 | 450,000 | 450,000 | ||||||
Senior Notes C, 6.375% fixed-rate, due February 2013 | 350,000 | 350,000 | ||||||
Senior Notes D, 6.875% fixed-rate, due March 2033 | 500,000 | 500,000 | ||||||
Senior Notes E, 4.00% fixed-rate, due October 2007 | 500,000 | 500,000 | ||||||
Senior Notes F, 4.625% fixed-rate, due October 2009 | 500,000 | 500,000 | ||||||
Senior Notes G, 5.60% fixed-rate, due October 2014 | 650,000 | 650,000 | ||||||
Senior Notes H, 6.65% fixed-rate, due October 2034 | 350,000 | 350,000 | ||||||
Senior Notes I, 5.00% fixed-rate, due March 2015 | 250,000 | 250,000 | ||||||
Senior Notes J, 5.75% fixed-rate, due March 2035 | 250,000 | 250,000 | ||||||
Senior Notes K, 4.950% fixed-rate, due June 2010 | 500,000 | 500,000 | ||||||
Dixie Revolving Credit Facility, variable rate, due June 2010(2) | 10,000 | 17,000 | ||||||
Other, 8.75% fixed-rate, due June 2010(5) | 5,068 | 5,068 | ||||||
Total principal amount of senior debt obligations | 4,779,068 | 4,866,068 | ||||||
Operating Partnership Junior Subordinated Notes A, due August 2066 | 550,000 | — | ||||||
Total principal amount of senior and junior debt obligations | 5,329,068 | 4,866,068 | ||||||
Other, including unamortized discounts and premiums and changes in fair value(3) | (33,478 | ) | (32,287 | ) | ||||
Long-term debt(4) | $ | 5,295,590 | $ | 4,833,781 | ||||
Standby letters of credit outstanding | $ | 49,858 | $ | 33,129 | ||||
(1) | In June 2006, the Operating Partnership executed a second amendment (the “Second Amendment”) to the credit agreement governing its Multi-Year Revolving Credit Facility. The Second Amendment, among other things, extends the maturity date of amounts borrowed under the Multi-Year Revolving Credit Facility from October 2010 to October 2011 with respect to $1.25 billion of the commitments. Borrowings with respect to the remaining $48 million in commitments mature in October 2010. | |
(2) | The maturity date of this facility was extended from June 2007 to June 2010 in August 2006. The other terms of the Dixie facility remain unchanged from those described in our annual report on Form 10-K for the year ended December 31, 2005. In accordance with GAAP, we consolidated Dixie’s debt with that of our own; however, we are not obligated to make interest or debt payments with respects to Dixie’s debt. | |
(3) | The December 31, 2006 amount includes $29.1 million related to fair value hedges and a net $4.4 million in unamortized discounts and premiums. The December 31, 2005 amount includes $19.2 million related to fair value hedges and a net $13.1 million in unamortized discounts and premiums. | |
(4) | In accordance with SFAS 6, “Classification of Short-Term Obligations Expected to be Refinanced,” long-term and current maturities of debt reflects the classification of such obligations at December 31, 2006. With respect to Senior Notes E due in October 2007, the Operating Partnership has the ability to use available credit capacity under its Multi-Year Revolving Credit Facility to fund the repayment of this debt. | |
(5) | Represents the remaining debt obligations assumed in connection with the GulfTerra merger. |
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Our | ||||||||
Ownership | ||||||||
Interest | Total | |||||||
Cameron Highway | 50.0 | % | $ | 415,000 | ||||
Poseidon | 36.0 | % | 91,000 | |||||
Evangeline | 49.5 | % | 25,650 | |||||
Total | $ | 531,650 | ||||||
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Net cash flows provided by operating activities | $ | 1,175,069 | $ | 631,708 | $ | 391,541 | ||||||
Net cash used in investing activities | 1,689,288 | 1,130,395 | 941,424 | |||||||||
Net cash provided by financing activities | 494,972 | 516,229 | 543,973 |
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• | Gross operating margin for the year ended December 31, 2006 increased $226.1 million over that recorded for the year ended December 31, 2005. The increase in gross operating margin is discussed under “Results of Operations” within this Item 7. | ||
• | With respect to changes in operating accounts, the timing of cash receipts and disbursements improved year-to-year generally due to the successful integration of acquired businesses and increased efficiencies. As to cash receipts, the average collection period for accounts receivable during the year ended December 31, 2006 improved approximately nine days when compared to the year ended December 31, 2005, with the related turnover rate increasing 26% year-to-year. In addition, as to cash disbursements, our payable turnover rate increased significantly year-to-year. |
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• | Gross operating margin for the year ended December 31, 2005 increased $481.2 million over that recorded for the year ended December 31, 2004. The increase in gross operating margin is discussed under “Results of Operations” within this Item 7. | ||
• | Cash payments for interest for the year ended December 31, 2005 increased $103.3 million over that recorded for the year ended December 31, 2004. The increase in cash outflows for interest was due to the additional debt we incurred to complete the GulfTerra Merger. | ||
• | The carrying value of our inventories increased from $189 million at December 31, 2004 to $339.6 million at December 31, 2005. The $150.6 million increase is primarily due to higher commodity prices during 2005 when compared to 2004 and an increase in volumes purchased and held in inventory in connection with our marketing activities at December 31, 2005 versus December 31, 2004. | ||
• | With respect to changes in operating accounts, the timing of cash disbursements slowed following the GulfTerra Merger as integration activities were ongoing. A slight improvement in the collection of accounts receivable also added to our operating cash flows. |
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• | Mont Belvieu Caverns, LLC(“Mont Belvieu Caverns”), a recently formed subsidiary, which owns salt dome storage caverns located in Mont Belvieu, Texas that receive, store and deliver NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States; | ||
• | Acadian Gas, LLC(“Acadian Gas”), which owns an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore |
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pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. A subsidiary of Acadian Gas owns a 49.5% equity interest in Evangeline Gas Pipeline, L.P. (“Evangeline”); | |||
• | Sabine Propylene Pipeline L.P.(“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana; | ||
• | Enterprise Lou-Tex Propylene Pipeline L.P.(“Lou-Tex Propylene”), which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and | ||
• | South Texas NGL Pipelines, LLC(“South Texas NGL”), a recently formed subsidiary, which began transporting NGLs from Corpus Christi, Texas to Mont Belvieu, Texas in January 2007. South Texas NGL owns the DEP South Texas NGL Pipeline System. |
• | We utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses; | ||
• | We buy natural gas from and sell natural gas to Acadian Gas in connection with its normal business activities; and | ||
• | We are the sole shipper on the DEP South Texas NGL Pipeline System. |
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Payment or Settlement due by Period | ||||||||||||||||||||
Less than | 1-3 | 3-5 | More than | |||||||||||||||||
Contractual Obligations | Total | 1 year | years | years | 5 years | |||||||||||||||
Scheduled maturities of long-term debt | $ | 5,329,068 | $ | — | $ | 500,000 | $ | 1,929,068 | $ | 2,900,000 | ||||||||||
Estimated cash payments for interest | $ | 5,703,440 | $ | 325,267 | $ | 613,348 | $ | 465,947 | $ | 4,298,878 | ||||||||||
Operating lease obligations | $ | 274,700 | $ | 19,190 | $ | 36,251 | $ | 31,951 | $ | 187,308 | ||||||||||
Purchase obligations: | ||||||||||||||||||||
Product purchase commitments: | ||||||||||||||||||||
Estimated payment obligations: | ||||||||||||||||||||
Natural gas | $ | 920,736 | $ | 153,316 | $ | 307,052 | $ | 306,632 | $ | 153,736 | ||||||||||
NGLs | $ | 2,902,805 | $ | 959,127 | $ | 436,885 | $ | 426,630 | $ | 1,080,163 | ||||||||||
Petrochemicals | $ | 2,656,633 | $ | 1,110,957 | $ | 693,362 | $ | 339,434 | $ | 512,880 | ||||||||||
Other | $ | 79,418 | $ | 35,183 | $ | 41,334 | $ | 1,424 | $ | 1,477 | ||||||||||
Underlying major volume commitments: | ||||||||||||||||||||
Natural gas (in BBtus) | 109,600 | 18,250 | 36,550 | 36,500 | 18,300 | |||||||||||||||
NGLs (in MBbls) | 68,331 | 21,957 | 10,408 | 10,172 | 25,794 | |||||||||||||||
Petrochemicals (in MBbls) | 45,535 | 19,250 | 11,749 | 5,694 | 8,842 | |||||||||||||||
Service payment commitments | $ | 15,725 | $ | 10,413 | $ | 4,659 | $ | 186 | $ | 467 | ||||||||||
Capital expenditure commitments | $ | 239,000 | $ | 239,000 | ||||||||||||||||
Other Long-Term Liabilities, as reflected in our Consolidated Balance Sheet | $ | 86,121 | $ | — | $ | 14,101 | $ | 4,004 | $ | 68,016 | ||||||||||
Total | $ | 18,207,646 | $ | 2,852,453 | $ | 2,646,992 | $ | 3,505,276 | $ | 9,202,925 | ||||||||||
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Revenues from consolidated operations | ||||||||||||
EPCO and affiliates | $ | 98,671 | $ | 311 | $ | 2,697 | ||||||
Shell | — | — | 542,912 | |||||||||
Unconsolidated affiliates | 304,559 | 354,461 | 258,541 | |||||||||
Total | $ | 403,230 | $ | 354,772 | $ | 804,150 | ||||||
Operating costs and expenses | ||||||||||||
EPCO and affiliates | $ | 311,537 | $ | 293,134 | $ | 203,100 | ||||||
Shell | — | — | 725,420 | |||||||||
Unconsolidated affiliates | 31,606 | 23,563 | 37,587 | |||||||||
Total | $ | 343,143 | $ | 316,697 | $ | 966,107 | ||||||
General and administrative expenses | ||||||||||||
EPCO and affiliates | $ | 41,265 | $ | 40,954 | $ | 29,307 | ||||||
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For the Year the Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Total non-GAAP segment gross operating margin | $ | 1,362,449 | $ | 1,136,347 | $ | 655,191 | ||||||
Adjustments to reconcile total non-GAAP gross operating margin to GAAP operating income: | ||||||||||||
Depreciation, amortization and accretion in operating costs and expenses | (440,256 | ) | (413,441 | ) | (193,734 | ) | ||||||
Retained lease expense, net in operating costs and expenses | (2,109 | ) | (2,112 | ) | (7,705 | ) | ||||||
Gain on sale of assets in operating costs and expenses | 3,359 | 4,488 | 15,901 | |||||||||
General and administrative costs | (63,391 | ) | (62,266 | ) | (46,659 | ) | ||||||
GAAP consolidated operating income | 860,052 | 663,016 | 422,994 | |||||||||
Other net expense, primarily interest expense | (229,967 | ) | (225,178 | ) | (153,625 | ) | ||||||
GAAP income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles | $ | 630,085 | $ | 437,838 | $ | 269,369 | ||||||
• | We recognized, as a benefit, a cumulative effect of a change in accounting principle of $1.5 million in 2006 based on the Statement of Financial Accounting Standards (“SFAS”) 123(R), “Share-Based Payment,” requirements to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards. | ||
• | We recorded a $4.2 million non-cash expense related to certain asset retirement obligations in 2005 due to our implementation of FIN 47 as of December 31, 2005. | ||
• | We recorded a combined $10.8 million non-cash gain in 2004 related to the impact of (i) changing the method our BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (ii) changing the method in which we account for our investment in VESCO from the cost method to the equity method. |
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• | Emerging Issues Task Force No. 06-3, “How Taxes Collected From Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation),” | ||
• | SFAS 155, “Accounting for Certain Hybrid Financial Instruments,” | ||
• | SFAS 157, “Fair Value Measurements,” and | ||
• | SFAS 159, “Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115.” |
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Number | Period Covered | Termination | Fixed to | Notional | ||||||||||
Hedged Fixed Rate Debt | Of Swaps | by Swap | Date of Swap | Variable Rate(1) | Amount | |||||||||
Senior Notes B, 7.50% fixed rate, due Feb. 2011 | 1 | Jan. 2004 to Feb. 2011 | Feb. 2011 | 7.50% to 8.89% | $50 million | |||||||||
Senior Notes C, 6.375% fixed rate, due Feb. 2013 | 2 | Jan. 2004 to Feb. 2013 | Feb. 2013 | 6.38% to 7.43% | $200 million | |||||||||
Senior Notes G, 5.6% fixed rate, due Oct. 2014 | 6 | 4th Qtr. 2004 to Oct. 2014 | Oct. 2014 | 5.60% to 6.33% | $600 million | |||||||||
Senior Notes K, 4.95% fixed rate, due June 2010 | 2 | Aug. 2005 to June 2010 | June 2010 | 4.95% to 5.76% | $200 million |
(1) | The variable rate indicated is the all-in variable rate for the current settlement period. |
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Swap Fair Value at | ||||||||||||||||
Resulting | ||||||||||||||||
Scenario | Classification | December 31, 2005 | December 31, 2006 | February 7, 2007 | ||||||||||||
FV assuming no change in underlying interest rates | Asset (Liability) | $ | (19,179 | ) | $ | (29,060 | ) | $ | (31,918 | ) | ||||||
FV assuming 10% increase in underlying interest rates | Asset (Liability) | (50,308 | ) | (56,249 | ) | (58,956 | ) | |||||||||
FV assuming 10% decrease in underlying interest rates | Asset (Liability) | 11,950 | (1,872 | ) | (4,881 | ) |
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Commodity Financial Instrument Portfolio FV | ||||||||||||||||
Resulting | ||||||||||||||||
Scenario | Classification | December 31, 2005 | December 31, 2006 | February 7, 2007 | ||||||||||||
FV assuming no change in underlying commodity prices | Asset (Liability) | $ | (53 | ) | $ | (3,184 | ) | $ | 549 | |||||||
FV assuming 10% increase in underlying commodity prices | Asset (Liability) | (53 | ) | (2,119 | ) | 1,734 | ||||||||||
FV assuming 10% decrease in underlying commodity prices | Asset (Liability) | (53 | ) | (4,249 | ) | (637 | ) |
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(i) | pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets, | ||
(ii) | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and | ||
(iii) | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. |
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OVER FINANCIAL REPORTING AS OF DECEMBER 31, 2006
/s/ Robert G. Phillips | /s/ Michael A. Creel | |||||||
Name: | Robert G. Phillips | Name: | Michael A. Creel | |||||
Title: | Chief Executive Officer of | Title: | Chief Financial Officer of | |||||
our general partner, | our general partner, | |||||||
Enterprise Products GP, LLC | Enterprise Products GP, LLC |
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Unitholders of Enterprise Products Partners L.P.
Houston, Texas
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February 28, 2007
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§ | monitoring the integrity of our financial reporting process and related systems of internal control; | ||
§ | ensuring our legal and regulatory compliance and that of Enterprise Products GP; | ||
§ | overseeing the independence and performance of our independent public accountants; | ||
§ | approving all services performed by our independent public accountants; | ||
§ | providing for an avenue of communication among the independent public accountants, management, internal audit function and the Board; | ||
§ | encouraging adherence to and continuous improvement of our policies, procedures and practices at all levels; | ||
§ | reviewing areas of potential significant financial risk to our businesses; and | ||
§ | approving awards granted under our 1998 Long-Term Incentive Plan. |
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Name | Age | Position with Enterprise Products GP | ||||
Dan L. Duncan(1) | 74 | Director and Chairman | ||||
Robert G. Phillips(1) | 52 | Director, President and Chief Executive Officer | ||||
Dr. Ralph S. Cunningham(1) | 66 | Director, Group Executive Vice President and Chief Operating Officer | ||||
Michael A. Creel(1) | 53 | Director, Executive Vice President and Chief Financial Officer | ||||
Richard H. Bachmann(1) | 54 | Director, Executive Vice President, Chief Legal Officer and Secretary | ||||
W. Randall Fowler(1) | 50 | Director, Senior Vice President and Treasurer | ||||
E. William Barnett(2,3) | 74 | Director | ||||
Rex C. Ross(2) | 63 | Director | ||||
Charles M. Rampacek(2) | 63 | Director | ||||
James H. Lytal(1) | 49 | Executive Vice President | ||||
A.J. Teague(1) | 61 | Executive Vice President | ||||
Gil H. Radtke | 46 | Senior Vice President | ||||
James M. Collingsworth | 52 | Senior Vice President | ||||
Michael J. Knesek(1) | 52 | Senior Vice President, Controller and Principal Accounting Officer |
(1) | Executive officer | |
(2) | Member of ACG Committee | |
(3) | Chairman of ACG Committee |
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Name and | Unit | Option | All Other | |||||||||||||||||||||||||
Principal | Salary | Bonus | Awards | Awards | Compensation | Total | ||||||||||||||||||||||
Position | Year | ($) | ($)(2) | ($)(3) | ($)(4) | ($)(5) | ($) | |||||||||||||||||||||
Enterprise Products GP: | ||||||||||||||||||||||||||||
Robert G. Phillips, CEO | 2006 | $ | 722,500 | $ | 300,000 | $ | 660,270 | $ | 357,209 | $ | 150,984 | $ | 2,190,962 | |||||||||||||||
Michael A. Creel, CFO(1) | 2006 | $ | 306,000 | $ | 125,000 | $ | 303,622 | $ | 23,613 | $ | 71,812 | $ | 830,048 | |||||||||||||||
James H. Lytal | 2006 | $ | 367,500 | $ | 187,500 | $ | 455,462 | $ | 47,227 | $ | 101,639 | $ | 1,159,327 | |||||||||||||||
A.J. Teague | 2006 | $ | 428,480 | $ | 250,000 | $ | 299,984 | $ | 47,227 | $ | 69,563 | $ | 1,095,254 | |||||||||||||||
Ralph S. Cunningham | 2006 | $ | 478,667 | $ | 250,000 | $ | 52,815 | $ | 13,707 | $ | 33,208 | $ | 828,397 |
(1) | Amounts presented reflect compensation allocated to us based on the percentage of time Mr. Creel spent on our consolidated business activities during 2006. | |
(2) | Amounts represent discretionary annual cash awards accrued for the year ended December 31, 2006. Payment of these amounts was made in February 2007. | |
(3) | Amounts represent expense recognized in accordance with SFAS 123(R) with respect to restricted unit and Employee Partnership awards for the year ended December 31, 2006. | |
(4) | Amounts represent expense recognized in accordance with SFAS 123(R) with respect to unit option awards for the year ended December 31, 2006. | |
(5) | Amounts primarily represent (i) matching contributions under funded, qualified, defined contribution retirement plans, (ii) quarterly distributions received from restricted unit awards and (iii) the imputed value of life insurance premiums paid on behalf of the officer. |
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§ | Annual base salary; | ||
§ | Discretionary annual cash awards; | ||
§ | Awards under long-term incentive arrangements; and | ||
§ | Other compensation, including very limited perquisites. |
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Grant | ||||||||||||||||||||||||
Exercise | Date Fair | |||||||||||||||||||||||
or Base | Value of | |||||||||||||||||||||||
Estimated Future Payouts Under | Price of | Unit and | ||||||||||||||||||||||
Equity Incentive Plan Awards | Option | Option | ||||||||||||||||||||||
Grant | Threshold | Target | Maximum | Awards | Awards | |||||||||||||||||||
Name | Date | (#) | (#) | (#) | ($/Unit) | ($)(1) | ||||||||||||||||||
Restricted unit awards: | ||||||||||||||||||||||||
Robert G. Phillips | 5/1/2006 | — | 24,000 | — | — | $ | 549,881 | |||||||||||||||||
Michael A. Creel | 5/1/2006 | — | 12,000 | — | — | $ | 151,217 | |||||||||||||||||
James H. Lytal | 5/1/2006 | — | 12,000 | — | — | $ | 274,940 | |||||||||||||||||
A. J. Teague | 5/1/2006 | — | 12,000 | — | — | $ | 274,940 | |||||||||||||||||
Ralph S. Cunningham | 5/1/2006 | — | 12,000 | — | — | $ | 274,940 | |||||||||||||||||
Unit option awards: | ||||||||||||||||||||||||
Robert G. Phillips | 5/1/2006 | — | 80,000 | — | $ | 24.85 | $ | 164,483 | ||||||||||||||||
Michael A. Creel | 5/1/2006 | — | 40,000 | — | $ | 24.85 | $ | 41,121 | ||||||||||||||||
James H. Lytal | 5/1/2006 | — | 40,000 | — | $ | 24.85 | $ | 82,241 | ||||||||||||||||
A. J. Teague | 5/1/2006 | — | 40,000 | — | $ | 24.85 | $ | 82,241 | ||||||||||||||||
Ralph S. Cunningham | 5/1/2006 | — | 40,000 | — | $ | 24.85 | $ | 82,241 | ||||||||||||||||
EPE Unit II profits interest award: | ||||||||||||||||||||||||
Ralph S. Cunningham | 12/5/2006 | — | — | — | — | $ | 212,289 |
(1) | Amounts presented reflect that portion of grant date fair value allocable to us based on the percentage of time each officer spent on our consolidated business activities during 2006. Based on current allocations, we estimate that the consolidated compensation expense we record for each named executive officer with respect to these awards will equal these amounts over time. For the period in which these awards were outstanding during 2006, we recognized a total of $317 thousand of consolidated compensation expense for these awards. The remaining portion of grant date fair value will be recognized as expense in future periods. |
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Option Awards | Unit Awards | |||||||||||||||||||
Number of Units | Number | Market | ||||||||||||||||||
Underlying | Option | of Units | Value of Units | |||||||||||||||||
Options | Exercise | Option | That Have | That Have | ||||||||||||||||
Unexercisable | Price | Expiration | Not Vested | Not Vested | ||||||||||||||||
Name | (#) | ($/Unit) | Date | (#) | ($) | |||||||||||||||
Robert G. Phillips | ||||||||||||||||||||
September 30, 2004 option award(4) | 500,000 | $ | 23.18 | 9/30/2014 | ||||||||||||||||
August 4, 2005 option award(2) | 70,000 | $ | 26.47 | 8/4/2015 | ||||||||||||||||
May 1, 2006 option award(3) | 80,000 | $ | 24.85 | 5/1/2016 | ||||||||||||||||
Restricted unit awards(5) | 86,553 | $ | 2,508,306 | |||||||||||||||||
Employee Partnership award(6) | 28,098 | $ | 1,038,794 | |||||||||||||||||
Michael A. Creel : | ||||||||||||||||||||
May 10, 2004 option award(1) | 35,000 | $ | 20.00 | 5/10/2014 | ||||||||||||||||
August 4, 2005 option award(2) | 35,000 | $ | 26.47 | 8/4/2015 | ||||||||||||||||
May 1, 2006 option award(3) | 40,000 | $ | 24.85 | 5/1/2016 | ||||||||||||||||
Restricted unit awards(5) | 76,553 | $ | 2,218,506 | |||||||||||||||||
Employee Partnership award(6) | 28,098 | $ | 1,038,794 | |||||||||||||||||
James H. Lytal: | ||||||||||||||||||||
September 30, 2004 option award(4) | 35,000 | $ | 23.18 | 9/30/2014 | ||||||||||||||||
August 4, 2005 option award(2) | 35,000 | $ | 26.47 | 8/4/2015 | ||||||||||||||||
May 1, 2006 option award(3) | 40,000 | $ | 24.85 | 5/1/2016 | ||||||||||||||||
Restricted unit awards(5) | 59,532 | $ | 1,725,237 | |||||||||||||||||
Employee Partnership award(6) | 18,872 | $ | 697,693 | |||||||||||||||||
A.J. Teague: | ||||||||||||||||||||
May 10, 2004 option award(1) | 35,000 | $ | 20.00 | 5/10/2014 | ||||||||||||||||
August 4, 2005 option award(2) | 35,000 | $ | 26.47 | 8/4/2015 | ||||||||||||||||
May 1, 2006 option award(3) | 40,000 | $ | 24.85 | 5/1/2016 | ||||||||||||||||
Restricted unit awards(5) | 34,000 | $ | 985,320 | |||||||||||||||||
Employee Partnership award(6) | 18,872 | $ | 697,693 | |||||||||||||||||
Ralph S. Cunningham | ||||||||||||||||||||
May 1, 2006 option award(3) | 40,000 | $ | 24.85 | 5/1/2016 | ||||||||||||||||
Restricted unit awards(5) | 12,000 | $ | 347,760 | |||||||||||||||||
Employee Partnership award(7) | 152 | $ | 5,603 |
(1) | These awards vest on May 10, 2008. | |
(2) | These awards vest on August 4, 2009. | |
(3) | These awards vest on May 1, 2010. | |
(4) | This award vests on September 30, 2008. | |
(5) | The total number of nonvested restricted units held by our named executive officers at December 31, 2006 was 268,638. Of this amount, 24,000 vest on May 28, 2008, 12,000 vest on September 30, 2008, 110,638 vest on October 12, 2008, 50,000 vest on August 4, 2009 and 72,000 vest on May 1, 2010. The estimated market value of these nonvested restricted units is based on a closing price of $28.98 per unit on December 29, 2006. | |
(6) | The EPE Unit I profits interests awards vest on August 30, 2010. See “Summary of Long-Term Incentive Arrangements – Employee Partnership awards” for additional information regarding these awards. | |
(7) | This EPE Unit II profits interest award vests on December 5, 2011. See “Summary of Long-Term Incentive Arrangements – Employee Partnership awards” for additional information regarding these awards. |
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Fees Earned | ||||||||||||||||||||
or Paid | Unit | Option | All other | |||||||||||||||||
in Cash | Awards | Awards | Compensation | Total | ||||||||||||||||
Name | ($) | ($) | ($)(3) | ($)(7) | ($) | |||||||||||||||
Current directors: | ||||||||||||||||||||
E. William Barnett | $ | 32,500 | $ | 8,936 | (1) | $ | 9,159 | (4) | $ | 2,244 | $ | 52,839 | ||||||||
Rex C. Ross | $ | 6,250 | — | $ | 6,759 | (5) | $ | — | $ | 13,009 | ||||||||||
Charles M. Rampacek | $ | 6,250 | — | $ | 6,759 | (6) | $ | — | $ | 13,009 | ||||||||||
Former directors: | ||||||||||||||||||||
Philip C. Jackson | $ | 24,435 | $ | 36,336 | (2) | — | $ | 1,016 | $ | 61,787 | ||||||||||
Stephen L. Baum | $ | 19,565 | $ | 25,785 | (2) | — | $ | 449 | $ | 45,799 | ||||||||||
W. Matt Ralls | $ | 3,972 | $ | 25,603 | (2) | — | $ | 532 | $ | 30,108 |
(1) | Mr. Barnett holds 1,744 of our nonvested restricted units. Of this amount, 269 units vest on May 24, 2009, 475 units vest on August 4, 2009, 500 units vest on February 21, 2010 and 500 units vest on August 2, 2010. At December 31, 2006, the total market value of these units was $51 thousand based on a closing market price of $28.98 per common unit at December 29, 2006. The dollar amount presented under the column labeled “Unit Awards” for Mr. Barnett represents the expense recognized by Enterprise Products GP during 2006 related to these awards attributable to his service during 2006. | |
(2) | The restricted units held by these former directors vested upon their respective resignation dates (see Item 10) and converted to common units on a one-for-one basis. The dollar amounts presented under the column labeled “Unit Awards” for Messrs. Jackson, Baum and Ralls represent the expense recognized by Enterprise Products GP during 2006 related to these awards, including the acceleration of expense amounts due to each director’s resignation. | |
(3) | Amount presented reflects the compensation expense recognized by Enterprise Products GP related to unit appreciation rights granted during 2006 under letter agreements. | |
(4) | At December 31, 2006, the fair value of UARs granted to Mr. Barnett was $195 thousand. | |
(5) | At December 31, 2006, the fair value of UARs granted to Mr. Ross was $202 thousand. | |
(6) | At December 31, 2006, the fair value of UARs granted to Mr. Rampacek was $202 thousand. | |
(7) | Amounts primarily represent quarterly distributions received from restricted unit awards. |
§ | Each independent director receives $50,000 in cash and $25,000 worth of restricted units annually. | ||
§ | If the individual serves as chairman of a committee of the Board, then he receives an additional $15,000 in cash annually. |
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Amount and | ||||||||||||
Nature of | ||||||||||||
Title of | Name and Address | Beneficial | Percent | |||||||||
Class | of Beneficial Owner | Ownership | of Class | |||||||||
Common units | Dan L. Duncan | 147,007,446 | (1) | 34.0 | % | |||||||
1100 Louisiana Street, 10th Floor | ||||||||||||
Houston, Texas 77002 |
(1) | For a detailed listing of ownership amounts that comprise Mr. Duncan’s total beneficial ownership of our common units, see the table presented in the following section, “Security Ownership of Management,” within this Item 12. |
§ | each of our named executive officers; | ||
§ | all of the current directors of Enterprise Products GP; and | ||
§ | all of the current directors and executive officers of Enterprise Products GP as a group. |
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Limited Partner Ownership Interests In | ||||||||||||||||
Enterprise Products Partners | Enterprise GP Holdings | |||||||||||||||
Amount and | Amount and | |||||||||||||||
Nature Of | Nature Of | |||||||||||||||
Name of | Beneficial | Percent of | Beneficial | Percent of | ||||||||||||
Beneficial Owner | Ownership | Class | Ownership | Class | ||||||||||||
Dan L. Duncan: | ||||||||||||||||
Units owned by EPCO: | ||||||||||||||||
Through DFI Delaware Holdings, L.P. | 120,044,779 | 27.8 | % | — | — | |||||||||||
Through Duncan Family Interests, Inc. | — | — | 71,271,231 | 80.2 | % | |||||||||||
Through Enterprise GP Holdings L.P. | 13,454,498 | 3.1 | % | — | — | |||||||||||
EPCO (direct) | 41,500 | * | — | — | ||||||||||||
Units owned by Dan Duncan LLC(1) | — | — | 3,726,273 | 4.2 | % | |||||||||||
Units owned by EPE Unit I(2) | — | — | 1,821,428 | 2.1 | % | |||||||||||
Units owned by EPE Unit II(2) | — | — | 40,725 | * | ||||||||||||
Units owned by trusts(3) | 12,566,645 | 2.9 | % | 243,071 | * | |||||||||||
Units owned directly | 900,024 | * | — | — | ||||||||||||
Total for Dan L. Duncan | 147,007,446 | 34.0 | % | 77,102,728 | 86.8 | % | ||||||||||
Robert G. Phillips(4,5) | 130,702 | * | 75,000 | * | ||||||||||||
Dr. Ralph S. Cunningham(4) | 16,139 | * | — | * | ||||||||||||
Michael A. Creel(4) | 114,828 | * | 35,000 | * | ||||||||||||
Richard H. Bachmann | 116,252 | * | 20,469 | * | ||||||||||||
W. Randall Fowler | 60,057 | * | 3,000 | * | ||||||||||||
E. William Barnett | 1,744 | * | 10,000 | * | ||||||||||||
Charles M. Rampacek | — | — | — | — | ||||||||||||
Rex C. Ross | 16,170 | * | 4,400 | * | ||||||||||||
A. J. Teague(4) | 164,547 | * | 17,000 | * | ||||||||||||
James H. Lytal(4) | 76,825 | * | 5,000 | * | ||||||||||||
All current directors and executive officers of Enterprise Products GP, as a group, (14 individuals in total)(6) | 147,814,495 | 34.2 | % | 77,306,597 | 87.0 | % |
* | The beneficial ownership of each individual is less than 1% of the registrant’s common units outstanding. | |
(1) | Dan Duncan LLC is owned by Mr. Duncan. | |
(2) | As a result of EPCO’s ownership of the general partners of the Employee Partnerships, Mr. Duncan is deemed beneficial owner of the units held by these entities. | |
(3) | In addition to the units owned by EPCO, Mr. Duncan is deemed to be the beneficial owner of the common units owned by the Duncan Family 1998 Trust and the Duncan Family 2000 Trust, the beneficiaries of which are the shareholders of EPCO. | |
(4) | These individuals are our named executive officers for 2006. | |
(5) | The number of Enterprise Products Partners common units shown for Mr. Phllips includes 5,132 common units held by trusts for which he has disclaimed beneficial ownership. | |
(6) | Cumulatively, this group’s beneficial ownership amount includes 10,000 options to acquire Enterprise Products Partners common units that were issued under the 1998 Plan. These options are exercisable within 60 days of the filing date of this report. |
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Duncan Energy Partners | ||||||||
Amount | ||||||||
And Nature Of | ||||||||
Name of | Beneficial | Percent of | ||||||
Beneficial Owner | Ownership | Class | ||||||
Dan L. Duncan, through the Operating Partnership(1) | 5,371,571 | 26.4 | % | |||||
Richard H. Bachmann(2) | 10,000 | * | ||||||
Michael A. Creel(3) | 7,500 | * | ||||||
W. Randall Fowler | 2,000 | * | ||||||
Robert G. Phillips | 7,500 | * | ||||||
Dr. Ralph S. Cunningham | 3,000 | * | ||||||
Rex C. Ross | 5,000 | * | ||||||
All current directors and executive officers of Enterprise Products GP, as a group (14 individuals in total) | 5,419,171 | 26.6 | % |
* | The beneficial ownership of each individual is less than 1% of the registrant’s units outstanding. | |
(1) | The number of common units shown for Dan L. Duncan represents the final amount of common units issued to the Operating Partnership of Enterprise Products Partners in connection with its contribution of equity interests to Duncan Energy Partners on February 5, 2007. | |
(2) | Mr. Bachmann is the chief executive officer of Duncan Energy Partners. | |
(3) | Mr. Creel is the chief financial officer of Duncan Energy Partners. |
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 | 2,416,000 | (1) | $ | 23.32 | 2,025,443 | |||||||
Equity compensation plans not approved by unitholders: | ||||||||||||
None | ||||||||||||
Total for equity compensation plans | 2,416,000 | (1) | $ | 23.32 | 2,025,443 | |||||||
(1) | Of the 2,416,000 unit options outstanding at December 31, 2006, 591,000 were immediately exercisable and an additional 785,000, 450,000, and 590,000 options are exercisable in 2008, 2009 and 2010, respectively. |
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§ | EPCO and its private company subsidiaries; | ||
§ | Enterprise Products GP, our sole general partner; | ||
§ | Enterprise GP Holdings, which owns and controls our general partner; | ||
§ | Duncan Energy Partners, which is a public company subsidiary of ours; | ||
§ | TEPPCO and TEPPCO GP, which are controlled by affiliates of EPCO; and | ||
§ | the Employee Partnerships. |
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§ | indemnification for certain environmental liabilities, tax liabilities and right-of-way defects; | ||
§ | reimbursement of certain expenditures for South Texas NGL and Mont Belvieu Caverns; | ||
§ | a right of first refusal to the Operating Partnership on the equity interests in the current and future subsidiaries of Duncan Energy Partners and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business; and | ||
§ | a preemptive right with respect to equity securities issued by certain of Duncan Energy Partners’ subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing. |
§ | certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to Duncan Energy Partners on February 5, 2007 are located; | ||
§ | failure to obtain certain consents and permits necessary for Duncan Energy Partners to conduct its business that arise within three years after February 5, 2007; and | ||
§ | certain income tax liabilities related to the operation of the assets contributed to Duncan Energy Partner attributable to periods prior to February 5, 2007. |
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§ | Distributions of Cashflow–Each quarter, 100% of the cash distributions received by EPE Unit I from Enterprise GP Holdings will be distributed to the Class A limited partner until Duncan Family Interests has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by EPE Unit I will be distributed to the Class B limited partners. The Class A preferred return equals 1.5625% per quarter, or 6.25% per annum, of the Class A limited partner’s capital base. The Class A limited partner’s capital base equals $51 million plus any unpaid Class A preferred return from prior periods, less any distributions made |
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by EPE Unit I of proceeds from the sale of Enterprise GP Holdings units owned by EPE Unit I (as described below). | |||
§ | Liquidating Distributions–Upon liquidation of EPE Unit I, units having a fair market value equal to the Class A limited partner capital base will be distributed to Duncan Family Interests, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners. | ||
§ | Sale Proceeds–If EPE Unit I sells any of the 1,821,428 Enterprise GP Holdings units that it owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above. |
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§ | EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our business, properties and assets (in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services. | ||
§ | 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 in respect of the services provided to us by EPCO. | ||
§ | EPCO will allow us to participate as named insureds in its overall insurance program, with the associated premiums and other costs being allocated to us. |
§ | If a business opportunity to acquire “equity securities” (as defined)is presented to the EPCO Group, us and our general partner, Duncan Energy Partners, its general partner, and its operating partnership, or Enterprise GP Holdings and its general partner, then Enterprise GP Holdings will have the first right to pursue such opportunity. The term “equity securities” is defined to include: |
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§ | general partner interests (or securities which have characteristics similar to general partner interests) and incentive distribution rights or similar rights in publicly traded partnerships or interests in “persons” that own or control such general partner or similar interests (collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and | ||
§ | incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates. |
Enterprise GP Holdings will be presumed to desire to acquire the equity securities until such time as its general partner advises the EPCO Group, Enterprise Products GP and DEP Holdings that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by the chief executive officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings. If the purchase price is reasonably likely to be less than such threshold amount, the chief executive officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings. | |||
In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, Enterprise Products GP and DEP Holdings, we will have the second right to pursue such acquisition either for us or, if desired by us in our sole discretion, for the benefit of Duncan Energy Partners. In the event that we affirmatively direct the opportunity to Duncan Energy Partners, Duncan Energy Partners may pursue such acquisition. We will be presumed to desire to acquire the equity securities until such time as Enterprise Products GP advises the EPCO Group and DEP Holdings that we have abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, we will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing Enterprise Products GP’s chief executive officer and ACG Committee. In the event we abandon the acquisition opportunity for the equity securities and so notify the EPCO Group and DEP Holdings, the EPCO Group may pursue the acquisition or offer the opportunity to EPCO Holdings or TEPPCO, TEPPCO GP and their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates. | |||
§ | If any business opportunity not covered by the preceding bullet point (i.e. not involving “equity securities”) is presented to the EPCO Group, Enterprise GP Holdings, EPE Holdings, Duncan Energy Partners, DEP Holdings, our general partner or us, we will have the first right to pursue such opportunity either for us or, if desired by us in our sole discretion, for the benefit of Duncan Energy Partners. We will be presumed to desire to pursue the business opportunity until such time as Enterprise Products GP advises the EPCO Group, EPE Holdings and DEP Holdings that we have abandoned the pursuit of such business opportunity. | ||
In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the chief executive officer of Enterprise Products GP after consultation with and subject to the approval of the ACG Committee of Enterprise Products GP. If the purchase price or cost is reasonably likely to be less than such threshold amount, the chief executive officer of Enterprise Products GP may make the determination to decline the business opportunity without consulting Enterprise Products GP’s ACG Committee. In the event that we affirmatively direct the business opportunity to Duncan Energy Partners, Duncan Energy Partners may pursue such business opportunity. In the event that we abandon the business opportunity for us and for Duncan Energy |
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Partners and so notify the EPCO Group, EPE Holdings and DEP Holdings, Enterprise GP Holdings will have the second right to pursue such business opportunity, and will be presumed to desire to do so, until such time as EPE Holdings shall have determined to abandon the pursuit of such opportunity in accordance with the procedures described above, and shall have advised the EPCO Group that Enterprise GP Holdings has abandoned the pursuit of such acquisition. | |||
In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, the EPCO Group may either pursue the business opportunity or offer the business opportunity to EPCO Holdings or TEPPCO, TEPPCO GP and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates. |
§ | We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility. Revenues from Evangeline were $277.7 million, $318.8 million and $233.9 million for the years ended December 31, 2006, 2005 and 2004. In addition, we furnished $1.1 million in letters of credit on behalf of Evangeline at December 31, 2006. | ||
§ | We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. Expenses with Promix were $34.9 million, $26.0 million and $23.2 million for the years ended December 31, 2006, 2005 and 2004. Additionally, revenues from Promix were $21.8 million, $25.8 million and $18.6 million for the years ended December 31, 2006, 2005 and 2004. | ||
§ | We perform management services for certain of our unconsolidated affiliates. These fees were $8.9 million, $8.3 million and $2.1 million for the years ended December 31, 2006, 2005 and 2004. |
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§ | the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest; | ||
§ | any customary or accepted industry practices and any customary or historical dealings with a particular person; | ||
§ | any applicable generally accepted accounting practices or principles; and | ||
§ | such additional factors as the committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. |
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§ | Review a summary of the proposed transaction(s) that outlines (i) its terms and conditions (explicit and implicit), (ii) a brief history of the transaction, and (iii) the impact that the transaction will have on our unitholders and personnel, including earnings per unit and distributable cash flow. | ||
§ | Review due diligence findings by management and make additional due diligence requests, if necessary. | ||
§ | Engage third-party independent advisors, where necessary, to provide committee members with comparable market values, legal advice and similar services directly related to the proposed transaction. | ||
§ | Conduct interviews regarding the proposed transaction with the most knowledgeable company officials to ensure that the committee members have all relevant facts before rendering their judgment. |
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Revenues: | ||||
Sales of NGL products | $ | 98,645 | ||
Other | 26 | |||
Total revenues related to EPCO and affiliates | $ | 98,671 | ||
Operating costs and expenses: | ||||
Purchase of NGL products, including freight and storage | $ | 86,383 | ||
Reimbursement of operating employee costs | 200,324 | |||
Recognition of non-cash retained lease expense | 2,109 | |||
Office space lease expense | 2,168 | |||
Other | 20,553 | |||
Total operating costs and expenses related to EPCO and affiliates | 311,537 | |||
General and administrative costs: | ||||
Reimbursement of overhead employee costs | 15,989 | |||
Office space lease expense | 1,781 | |||
Other | 23,495 | |||
Total general and administrative costs related to EPCO and affiliates | 41,265 | |||
Total costs and expenses related to EPCO and affiliates | $ | 352,802 | ||
Cash distributions paid to Enterprise Products GP by us | $ | 101,805 | ||
Cash distributions paid by us to our common units beneficially owned by EPCO (see Item 12) | $ | 237,006 | ||
Non-cash expense amount recognized in connection with Employee Partnership equity awards | $ | 2,146 |
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For Year Ended December 31, | ||||||||
2006 | 2005 | |||||||
Audit Fees(1) | $ | 5,563 | $ | 4,892 | ||||
Audit-Related Fees(2) | 13 | 14 | ||||||
Tax Fees(3) | 319 | 407 | ||||||
All Other Fees(4) | n/a | n/a |
(1) | Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the audit of our annual financial statements and internal controls over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with 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. This category primarily includes services relating to internal control assessments and accounting-related consulting. | |
(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. This category primarily includes services relating to the preparation of unitholder annual K-1 statements, partnership tax planning and property tax assistance. | |
(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. No such services were rendered by Deloitte & Touche during the last two years. |
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Exhibit | ||
Number | Exhibit* | |
2.1 | Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 26, 2000). | |
2.2 | Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 8, 2002). | |
2.3 | Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002). | |
2.4 | Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002). | |
2.5 | Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002). | |
2.6 | 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). | |
2.7 | 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). | |
2.8 | 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). | |
2.9 | 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 the Form 8-K filed April 21, 2004). |
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Exhibit | ||
Number | Exhibit* | |
2.10 | Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003, (incorporated by reference to Exhibit 2.3 to Form 8-K filed December 15, 2003). | |
2.11 | Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Registration Statement on Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004). | |
2.12 | 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). | |
3.1 | Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005). | |
3.2 | Third Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of August 29, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 1, 2005). | |
3.3 | Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003)(incorporated by reference to Exhibit 3.1 to Form 8-K filed July 1, 2005). | |
3.4 | 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). | |
3.5 | 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). | |
3.6 | Certificate of Limited Partnership of Duncan Energy Partners L.P. (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P. Form S-1 Registration Statement, Reg. No. 333-138371, filed November 2, 2006). | |
4.1 | 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). | |
4.2 | 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). | |
4.3 | Global Note representing $350 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). | |
4.4 | 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 | Global Note representing $500 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). | |
4.6 | Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001). | |
4.7 | Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998). | |
4.8 | Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit “B” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC). | |
4.9 | Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “E” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC). |
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Exhibit | ||
Number | Exhibit* | |
4.10 | Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “C” to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC). | |
4.11 | Amendment No. 1, dated September 12, 2003, to Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit 4.1 to Form 8-K filed September 15, 2003). | |
4.12 | Agreement dated as of March 4, 2005 among Enterprise Products Partners L.P., Shell US Gas & Power LLC and Kayne Anderson MLP Investment Company (incorporated by reference to Exhibit 4.31 to Form S-3 Registration Statement, Reg. No. 333-123150, filed March 4, 2005). | |
4.13 | $750 Million Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.1 to Form 8-K filed on August 30, 2004). | |
4.14 | Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.13, above (incorporated by reference to Exhibit 4.2 to Form 8-K filed on August 30, 2004). | |
4.15 | First Amendment dated October 5, 2005, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as CO-Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 7, 2005). | |
4.16 | $2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citicorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, Citigroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Form 8-K filed on August 30, 2004). | |
4.17 | Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.16, above (incorporated by reference to Exhibit 4.4 to Form 8-K filed on August 30, 2004). | |
4.18 | Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004). | |
4.19 | First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6, 2004). | |
4.20 | Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6, 2004). | |
4.21 | Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6, 2004). | |
4.22 | Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6, 2004). | |
4.23 | Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005). |
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Exhibit | ||
Number | Exhibit* | |
4.24 | Global Note representing $500 million principal amount of 5.600% 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 on March 4, 2005). | |
4.25 | Global Note representing $150 million principal amount of 5.600% 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 on March 4, 2005). | |
4.26 | Global Note representing $350 million principal amount of 6.650% 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 on March 4, 2005). | |
4.27 | Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on March 15, 2005). | |
4.28 | Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3, 2005). | |
4.29 | Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3, 2005). | |
4.30 | Global Note representing $250,000,000 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 on November 4, 2005). | |
4.31 | Global Note representing $250,000,000 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 on November 4, 2005). | |
4.32 | Registration Rights Agreement dated as of March 2, 2005, among Enterprise Products Partners, L.P., Enterprise Products Operating L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.6 to Form 8-K filed on March 3, 2005). | |
4.33 | Assumption Agreement dated as of September 30, 2004 between Enterprise Products Partners L.P. and GulfTerra Energy Partners, L.P. relating to the assumption by Enterprise of GulfTerra’s obligations under the GulfTerra Series F2 Convertible Units (incorporated by reference to Exhibit 4.4 to Form 8-K/A-1 filed on October 5, 2004). | |
4.34 | Statement of Rights, Privileges and Limitations of Series F Convertible Units, included as Annex A to Third Amendment to the Second Amended and Restated Agreement of Limited Partnership of GulfTerra Energy Partners, L.P., dated May 16, 2003 (incorporated by reference to Exhibit 3.B.3 to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003). | |
4.35 | Unitholder Agreement between GulfTerra Energy Partners, L.P. and Fletcher International, Inc. dated May 16, 2003 (incorporated by reference to Exhibit 4.L to Current Report on Form 8-K of GulfTerra Energy Partners, L.P., file no. 001-11680, filed with the Commission on May 19, 2003). | |
4.36 | Indenture dated as of May 17, 2001 among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and the Chase Manhattan Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Registration Statement on Form S-4 filed June 25, 2001, Registration Nos. 333-63800 through 333-63800-20); First Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s 2002 First Quarter Form 10-Q); Second Supplemental Indenture dated as of April 18, 2002 (filed as Exhibit 4.E.2 to GulfTerra’s 2002 First Quarter Form 10-Q); Third Supplemental Indenture dated as of October 10, 2002 (filed as Exhibit 4.E.3 to GulfTerra’s 2002 Third Quarter Form 10-Q); Fourth Supplemental Indenture dated as of November 27, 2002 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Fifth Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.E.2 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Sixth Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.E.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680). |
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Exhibit | ||
Number | Exhibit* | |
4.37 | Seventh Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.E.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680). | |
4.38 | Indenture dated as of November 27, 2002 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee (filed as Exhibit 4.1 to GulfTerra’s Current Report of Form 8-K dated December 11, 2002); First Supplemental Indenture dated as of January 1, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K dated March 19, 2003); Second Supplemental Indenture dated as of June 20, 2003 (filed as Exhibit 4.1.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680). | |
4.39 | Third Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.1.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680). | |
4.40 | Indenture dated as of March 24, 2003 by and among GulfTerra Energy Partners, L.P., GulfTerra Energy Finance Corporation, the Subsidiary Guarantors named therein and JPMorgan Chase Bank, as Trustee dated as of March 24, 2003 (filed as Exhibit 4.K to GulfTerra’s Quarterly Report on Form 10-Q dated May 15, 2003); First Supplemental Indenture dated as of June 30, 2003 (filed as Exhibit 4.K.1 to GulfTerra’s 2003 Second Quarter Form 10-Q, file no. 001-11680). | |
4.41 | Second Supplemental Indenture dated as of August 17, 2004 (filed as Exhibit 4.K.1 to GulfTerra’s Current Report on Form 8-K filed on August 19, 2004, file no. 001-11680). | |
4.42 | Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Form 8-K filed on July 1, 2005). | |
4.43 | Seventh Supplemental Indenture dated as of June 1, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4, 2005). | |
4.44 | Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Form 10-Q filed November 4, 2005). | |
4.45 | Note Purchase Agreement dated as of December 15, 2005 among Cameron Highway Oil Pipeline Company and the Note Purchasers listed therein (incorporated by reference to Exhibit 4.1 to Form 8-K filed December 21, 2005.) | |
4.46 | Second Amendment dated June 22,2006, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004 among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents and Mizuho Corporate Bank, LTD., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006). | |
4.47# | Third Amendment dated January 5, 2007, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004 among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents and Mizuho Corporate Bank, LTD, SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents. | |
4.48 | Eighth Supplemental Indenture dated as of July 18, 2006 to Indenture dated 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 4.2 to Form 8-K filed July 19, 2006). | |
4.49 | Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K file July 19, 2006). | |
4.50 | Purchase Agreement, dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P. as Guarantor, and Enterprise Products Partners L.P., as buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006). | |
4.51 | Purchase Agreement dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P., as Guarantor, and Enterprise Products Partners L.P., as Buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006). |
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Exhibit | ||
Number | Exhibit* | |
10.1 | Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Registration Statement Form S-1/A filed July 8, 1998). | |
10.2 | Seventh Amendment to Conveyance of Gas Processing Rights, dated as of April 1, 2004 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Consolidated Energy Resources Inc., Shell Land & Energy Company, Shell Frontier Oil & Gas Inc. and Shell Gulf of Mexico Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 26, 2004). | |
10.3*** | Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of April 8, 2004 (incorporated by reference to Appendix B to Notice of Written Consent dated April 22, 2004, filed April 22, 2004). | |
10.4*** | Form of Option Grant Award under 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.2 to Form S-8 Registration Statement, Reg. No. 333-115633, filed May 19, 2004). | |
10.5*** | Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Form S-8 Registration Statement, Reg. No. 333-115633, filed May 19, 2004). | |
10.6*** | 1998 Omnibus Compensation Plan of GulfTerra Energy Partners, L.P., Amended and Restated as of January 1, 1999 (incorporated by reference to Exhibit 10.9 to Form 10-K for the year ended December 31, 1998 of GulfTerra Energy Partners, L.P., file no. 001-11680); Amendment No. 1, dated as of December 1, 1999 (incorporated by reference to Exhibit 10.8.1 to Form 10-Q for the quarter ended June 30, 2000 of GulfTerra Energy Partners, L.P., file no. 001-116800); Amendment No. 2 dated as of May 15, 2003 (incorporated by reference to Exhibit 10.M.1 to Form 10-Q for the quarter ended June 30, 2003 of GulfTerra Energy Partners, L.P., file no. 001-11680). | |
10.7 | Fourth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2007, but effective as of February 5, 2007 (incorporated by reference to Exhibit 10 to Form 8-K filed February 5, 2007 by Duncan Energy Partners). | |
10.8# | Amendment No. 1 to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007. | |
10.9*** | EPE Unit L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P., Commission file no. 1-32610, on September 1, 2005). | |
10.10*** | Enterprise Products Company 2005 EPE Long-Term Incentive Plan (amended and restated) (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006). | |
10.11*** | Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005). | |
10.11*** | Form of Phantom Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005). | |
10.13#*** | EPE Unit II, L.P. Agreement of Limited Partnership. | |
10.14 | Omnibus Agreement, dated as of February 5, 2007 by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership, L.P., Enterprise Lou-Tex Propylene Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian Gas, LLC, Mont Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC (incorporated by reference to Exhibit 10.19 to Form 8-K filed February 5, 2007 by Duncan Energy Partners). |
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Exhibit | ||
Number | Exhibit* | |
10.15 | Contribution, Conveyance And Assumption Agreement dated as of February 5, 2007, by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC and DEP Operating Partnership, L.P. (incorporated by reference to Exhibit 1.1 to Form 8-K filed February 5, 2007 by Duncan Energy Partners). | |
10.16*** | Form of Unit Appreciation Right Grant (Enterprise Products GP, LLC Directors) based upon the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by Enterprise GP Holdings on May 8, 2006). | |
12.1# | Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2006, 2005, 2004, 2003 and 2002. | |
18.1 | Letter regarding Change in Accounting Principles dated May 4, 2004 (incorporated by reference to Exhibit 18.1 to Form 10-Q filed May 10, 2004). | |
21.1# | List of subsidiaries as of February 28, 2007. | |
23.1# | Consent of Deloitte & Touche LLP. | |
31.1# | Sarbanes-Oxley Section 302 certification of Robert G. Phillips for Enterprise Products Partners L.P. for the December 31, 2006 annual report on Form 10-K. | |
31.2# | Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the December 31, 2006 annual report on Form 10-K. | |
32.1# | Section 1350 certification of Robert G. Phillips for the December 31, 2006 annual report on Form 10-K. | |
32.2# | Section 1350 certification of Michael A. Creel for the December 31, 2006 annual report on Form 10-K. |
* | With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323. | |
*** | Identifies management contract and compensatory plan arrangements. | |
# | Filed with this report. |
135
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ENTERPRISE PRODUCTS PARTNERS L.P. (A Delaware Limited Partnership) | ||||
By: | Enterprise Products GP, LLC, as general partner | |||
By: | /s/ Michael J. Knesek | Senior Vice President, Controller and Principal Accounting Officer of the general partner | ||
Michael J. Knesek |
Signature | Title (Position with Enterprise Products GP, LLC) | |
/s/ Dan L. Duncan | Director and Chairman | |
/s/ Robert G. Phillips | Director, President and Chief Executive Officer | |
/s/ Dr. Ralph S. Cunningham | Director, Group Executive Vice President and Chief Operating Officer | |
/s/ Michael A. Creel | Director, Executive Vice President and Chief Financial Officer | |
/s/ Richard H. Bachmann | Director, Executive Vice President, Chief Legal Officer and Secretary | |
/s/ W. Randall Fowler | Director, Senior Vice President and Treasurer | |
/s/ E. William Barnett | Director | |
/s/ Charles M. Rampacek | Director | |
/s/ Rex C. Ross | Director | |
/s/ Michael J. Knesek | Senior Vice President, Controller and Principal Accounting Officer |
136
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Page No. | ||
F-2 | ||
F-3 | ||
F-4 | ||
F-5 | ||
F-6 | ||
F-7 | ||
Note 1 – Partnership Organization | F-8 | |
Note 2 – Summary of Significant Accounting Policies | F-8 | |
Note 3 – Recent Accounting Developments | F-16 | |
Note 4 – Revenue Recognition | F-17 | |
Note 5 – Accounting for Equity Awards | F-19 | |
Note 6 – Employee Benefit Plans | F-24 | |
Note 7 – Financial Instruments | F-25 | |
Note 8 – Cumulative Effect of Changes in Accounting Principles | F-29 | |
Note 9 – Inventories | F-31 | |
Note 10 – Property, Plant and Equipment | F-33 | |
Note 11 – Investments In and Advances to Unconsolidated Affiliates | F-34 | |
Note 12 – Business Combinations | F-40 | |
Note 13 – Intangible Assets and Goodwill | F-45 | |
Note 14 – Debt Obligations | F-48 | |
Note 15 – Partners’ Equity and Distributions | F-53 | |
Note 16 – Business Segments | F-58 | |
Note 17 – Related Party Transactions | F-62 | |
Note 18 – Provision for Income Taxes | F-74 | |
Note 19 – Earnings Per Unit | F-75 | |
Note 20 – Commitments and Contingencies | F-77 | |
Note 21 – Significant Risks and Uncertainties | F-82 | |
Note 22 – Supplemental Cash Flow Information | F-84 | |
Note 23 – Quarterly Financial Information (Unaudited) | F-86 | |
Note 24 – Condensed Financial Information of Operating Partnership | F-86 | |
Note 25 – Subsequent Events | F-87 |
F-1
Table of Contents
Unitholders of Enterprise Products Partners L.P.
Houston, Texas
February 28, 2007
F-2
Table of Contents
(Dollars in thousands)
December 31, | |||||||||
2006 | 2005 | ||||||||
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 22,619 | $ | 42,098 | |||||
Restricted cash | 23,667 | 14,952 | |||||||
Accounts and notes receivable — trade, net of allowance for doubtful accounts of $23,406 at December 31, 2006 and $37,329 at December 31, 2005 | 1,306,290 | 1,448,026 | |||||||
Accounts receivable — related parties | 16,738 | 6,557 | |||||||
Inventories | 423,844 | 339,606 | |||||||
Prepaid and other current assets | 129,000 | 120,208 | |||||||
Total current assets | 1,922,158 | 1,971,447 | |||||||
Property, plant and equipment, net | 9,832,547 | 8,689,024 | |||||||
Investments in and advances to unconsolidated affiliates | 564,559 | 471,921 | |||||||
Intangible assets, net of accumulated amortization of $251,876 at December 31, 2006 and $163,121 at December 31, 2005 | 1,003,955 | 913,626 | |||||||
Goodwill | 590,541 | 494,033 | |||||||
Deferred tax asset | 1,855 | 3,606 | |||||||
Other assets | 74,103 | 47,359 | |||||||
Total assets | $ | 13,989,718 | $ | 12,591,016 | |||||
LIABILITIES AND PARTNERS’ EQUITY | |||||||||
Current liabilities: | |||||||||
Accounts payable – trade | $ | 277,070 | $ | 265,699 | |||||
Accounts payable – related parties | 6,785 | 23,367 | |||||||
Accrued gas payables | 1,364,493 | 1,372,837 | |||||||
Accrued expenses | 35,763 | 30,294 | |||||||
Accrued interest | 90,865 | 71,193 | |||||||
Other current liabilities | 209,945 | 126,881 | |||||||
Total current liabilities | 1,984,921 | 1,890,271 | |||||||
Long-term debt: (see Note 14) | |||||||||
Senior debt obligations – principal | 4,779,068 | 4,866,068 | |||||||
Junior Subordinated Notes A – principal | 550,000 | — | |||||||
Other | (33,478 | ) | (32,287 | ) | |||||
Total long-term debt | 5,295,590 | 4,833,781 | |||||||
Deferred tax liabilities | 13,723 | — | |||||||
Other long-term liabilities | 86,121 | 84,486 | |||||||
Minority interest | 129,130 | 103,169 | |||||||
Commitments and contingencies | |||||||||
Partners’ equity: | |||||||||
Limited Partners | |||||||||
Common units (431,303,193 units outstanding at December 31, 2006 and 389,109,564 units outstanding at December 31, 2005 ) | 6,320,577 | 5,542,700 | |||||||
Restricted common units (1,105,237 units outstanding at December 31, 2006 and 751,604 units outstanding at December 31, 2005) | 9,340 | 18,638 | |||||||
General partner | 129,175 | 113,496 | |||||||
Accumulated other comprehensive income | 21,141 | 19,072 | |||||||
Deferred compensation | — | (14,597 | ) | ||||||
Total partners’ equity | 6,480,233 | 5,679,309 | |||||||
Total liabilities and partners’ equity | $ | 13,989,718 | $ | 12,591,016 | |||||
F-3
Table of Contents
For Year Ended December 31, | |||||||||||||
2006 | 2005 | 2004 | |||||||||||
Revenues: | |||||||||||||
Third parties | $ | 13,587,739 | $ | 11,902,187 | $ | 7,517,052 | |||||||
Related parties | 403,230 | 354,772 | 804,150 | ||||||||||
Total (see Note 16) | 13,990,969 | 12,256,959 | 8,321,202 | ||||||||||
Costs and expenses: | |||||||||||||
Operating costs and expenses | |||||||||||||
Third parties | 12,745,948 | 11,229,528 | 6,938,229 | ||||||||||
Related parties | 343,143 | 316,697 | 966,107 | ||||||||||
Total operating costs and expenses | 13,089,091 | 11,546,225 | 7,904,336 | ||||||||||
General and administrative costs | |||||||||||||
Third parties | 22,126 | 21,312 | 17,352 | ||||||||||
Related parties | 41,265 | 40,954 | 29,307 | ||||||||||
Total general and administrative costs | 63,391 | 62,266 | 46,659 | ||||||||||
Total costs and expenses | 13,152,482 | 11,608,491 | 7,950,995 | ||||||||||
Equity in income of unconsolidated affiliates | 21,565 | 14,548 | 52,787 | ||||||||||
Operating income | 860,052 | 663,016 | 422,994 | ||||||||||
Other income (expense): | |||||||||||||
Interest expense | (238,023 | ) | (230,549 | ) | (155,740 | ) | |||||||
Interest income | 7,589 | 5,237 | 2,083 | ||||||||||
Other, net | 467 | 134 | 32 | ||||||||||
Other expense | (229,967 | ) | (225,178 | ) | (153,625 | ) | |||||||
Income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles | 630,085 | 437,838 | 269,369 | ||||||||||
Provision for income taxes | (21,323 | ) | (8,362 | ) | (3,761 | ) | |||||||
Income before minority interest and the cumulative effect of changes in accounting principles | 608,762 | 429,476 | 265,608 | ||||||||||
Minority interest | (9,079 | ) | (5,760 | ) | (8,128 | ) | |||||||
Income before the cumulative effect of changes in accounting principles | 599,683 | 423,716 | 257,480 | ||||||||||
Cumulative effect of changes in accounting principles (see Note 8) | 1,472 | (4,208 | ) | 10,781 | |||||||||
Net income | $ | 601,155 | $ | 419,508 | $ | 268,261 | |||||||
Net income allocation:(see Note 15) | |||||||||||||
Limited partners’ interest in net income | $ | 504,156 | $ | 348,512 | $ | 231,153 | |||||||
General partner interest in net income | $ | 96,999 | $ | 70,996 | $ | 37,108 | |||||||
Earnings per unit:(see Note 19) | |||||||||||||
Basic and diluted income per unit before changes in accounting principles | $ | 1.22 | $ | 0.92 | $ | 0.83 | |||||||
Basic and diluted income per unit | $ | 1.22 | $ | 0.91 | $ | 0.87 | |||||||
F-4
Table of Contents
For Year Ended December 31, | |||||||||||||
2006 | 2005 | 2004 | |||||||||||
Net income | $ | 601,155 | $ | 419,508 | $ | 268,261 | |||||||
Other comprehensive income: | |||||||||||||
Cash flow hedges: | |||||||||||||
Net commodity financial instrument gains during period | 7,574 | — | 1,434 | ||||||||||
Less: Reclassification adjustment for gain included in net income related to commodity financial instruments | — | (1,434 | ) | — | |||||||||
Net interest rate financial instrument gains during period | 19,405 | ||||||||||||
Less: Amortization of cash flow financing hedges | (4,234 | ) | (4,048 | ) | (1,275 | ) | |||||||
Total cash flow hedges | 3,340 | (5,482 | ) | 19,564 | |||||||||
Foreign currency translation adjustment | (807 | ) | — | — | |||||||||
Total other comprehensive income | 2,533 | (5,482 | ) | 19,564 | |||||||||
Comprehensive income | $ | 603,688 | $ | 414,026 | $ | 287,825 | |||||||
F-5
Table of Contents
For Year Ended December 31, | |||||||||||||
2006 | 2005 | 2004 | |||||||||||
Operating activities: | |||||||||||||
Net income | $ | 601,155 | $ | 419,508 | $ | 268,261 | |||||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||||||||||||
Depreciation, amortization and accretion in operating costs and expenses | 440,256 | 413,441 | 193,734 | ||||||||||
Depreciation and amortization in general and administrative costs | 7,186 | 7,184 | 1,650 | ||||||||||
Amortization in interest expense | 766 | 152 | 3,503 | ||||||||||
Equity in income of unconsolidated affiliates | (21,565 | ) | (14,548 | ) | (52,787 | ) | |||||||
Distributions received from unconsolidated affiliates | 43,032 | 56,058 | 68,027 | ||||||||||
Provision for impairment of long-lived asset | 88 | — | 4,114 | ||||||||||
Cumulative effect of changes in accounting principles | (1,472 | ) | 4,208 | (10,781 | ) | ||||||||
Operating lease expense paid by EPCO, Inc. | 2,109 | 2,112 | 7,705 | ||||||||||
Minority interest | 9,079 | 5,760 | 8,128 | ||||||||||
Gain on sale of assets | (3,359 | ) | (4,488 | ) | (15,901 | ) | |||||||
Deferred income tax expense | 14,427 | 8,594 | 9,608 | ||||||||||
Changes in fair market value of financial instruments | (51 | ) | 122 | 5 | |||||||||
Net effect of changes in operating accounts (see Note 22) | 83,418 | (266,395 | ) | (93,725 | ) | ||||||||
Net cash flows provided by operating activities | 1,175,069 | 631,708 | 391,541 | ||||||||||
Investing activities: | |||||||||||||
Capital expenditures | (1,341,070 | ) | (864,453 | ) | (182,057 | ) | |||||||
Contributions in aid of construction costs | 60,492 | 47,004 | 8,865 | ||||||||||
Proceeds from sale of assets | 3,927 | 44,746 | 6,882 | ||||||||||
Decrease (increase) in restricted cash | (8,715 | ) | 11,204 | (12,305 | ) | ||||||||
Cash used for business combinations (see Note 12) | (276,500 | ) | (326,602 | ) | (696,745 | ) | |||||||
Acquisition of intangible assets | — | (1,750 | ) | (1,652 | ) | ||||||||
Investments in unconsolidated affiliates | (138,266 | ) | (87,342 | ) | (57,948 | ) | |||||||
Advances from (to) unconsolidated affiliates | 10,844 | (702 | ) | (6,464 | ) | ||||||||
Return of investment from unconsolidated affiliate | — | 47,500 | — | ||||||||||
Cash used in investing activities | (1,689,288 | ) | (1,130,395 | ) | (941,424 | ) | |||||||
Financing activities: | |||||||||||||
Borrowings under debt agreements | 3,378,285 | 4,192,345 | 5,934,505 | ||||||||||
Repayments of debt | (2,907,000 | ) | (3,630,611 | ) | (5,808,877 | ) | |||||||
Debt issuance costs | (8,955 | ) | (9,297 | ) | (19,911 | ) | |||||||
Distributions paid to partners | (843,292 | ) | (716,699 | ) | (438,765 | ) | |||||||
Distributions paid to minority interests | (8,831 | ) | (5,724 | ) | (6,440 | ) | |||||||
Contributions from minority interests | 27,578 | 39,110 | 9,585 | ||||||||||
Contributions from general partner related to issuance of restricted units | — | 177 | — | ||||||||||
Net proceeds from issuance of common units | 857,187 | 646,928 | 846,077 | ||||||||||
Treasury units reissued | — | — | 8,394 | ||||||||||
Settlement of cash flow financing hedges | — | — | 19,405 | ||||||||||
Cash provided by financing activities | 494,972 | 516,229 | 543,973 | ||||||||||
Effect of exchange rate changes on cash | (232 | ) | — | — | |||||||||
Net change in cash and cash equivalents | (19,247 | ) | 17,542 | (5,910 | ) | ||||||||
Cash and cash equivalents, January 1 | 42,098 | 24,556 | 30,466 | ||||||||||
Cash and cash equivalents, December 31 | $ | 22,619 | $ | 42,098 | $ | 24,556 | |||||||
F-6
Table of Contents
Limited | General | Treasury | Deferred | |||||||||||||||||||||
Partners | Partner | units | Comp. | AOCI | Total | |||||||||||||||||||
Balance, December 31, 2003 | $ | 1,683,133 | $ | 34,349 | $ | (16,519 | ) | $ | — | $ | 4,990 | $ | 1,705,953 | |||||||||||
Net income | 231,153 | 37,108 | — | — | — | 268,261 | ||||||||||||||||||
Operating leases paid by EPCO, Inc. | 7,551 | 154 | — | — | — | 7,705 | ||||||||||||||||||
Cash distributions to partners | (394,434 | ) | (40,440 | ) | — | — | — | (434,874 | ) | |||||||||||||||
Unit option reimbursements to EPCO, Inc. | (3,813 | ) | (78 | ) | — | — | — | (3,891 | ) | |||||||||||||||
Net proceeds from sales of common units | 789,758 | 16,117 | — | — | — | 805,875 | ||||||||||||||||||
Proceeds from conversion of Series F2 convertible units to common units | 38,800 | 792 | — | — | — | 39,592 | ||||||||||||||||||
Proceeds from exercise of unit options | 398 | 8 | — | — | — | 406 | ||||||||||||||||||
Value of equity interests granted to complete GulfTerra Merger | 2,854,275 | 58,252 | — | (1,755 | ) | — | 2,910,772 | |||||||||||||||||
Other issuance of restricted units | 9,922 | 202 | — | (9,922 | ) | — | 202 | |||||||||||||||||
Amortization of deferred compensation | — | — | — | 826 | — | 826 | ||||||||||||||||||
Treasury units issued to satisfy unit options | 524 | 11 | 7,859 | — | — | 8,394 | ||||||||||||||||||
Cash flow hedges | — | — | — | — | 19,564 | 19,564 | ||||||||||||||||||
Balance, December 31, 2004 | 5,217,267 | 106,475 | (8,660 | ) | (10,851 | ) | 24,554 | 5,328,785 | ||||||||||||||||
Net income | 348,512 | 70,996 | — | — | — | 419,508 | ||||||||||||||||||
Operating leases paid by EPCO, Inc. | 2,070 | 42 | — | — | — | 2,112 | ||||||||||||||||||
Cash distributions to partners | (630,560 | ) | (76,752 | ) | — | — | — | (707,312 | ) | |||||||||||||||
Unit option reimbursements to EPCO, Inc. | (9,199 | ) | (188 | ) | — | — | — | (9,387 | ) | |||||||||||||||
Net proceeds from sales of common units | 612,616 | 12,502 | — | — | — | 625,118 | ||||||||||||||||||
Proceeds from exercise of unit options | 21,374 | 436 | — | — | — | 21,810 | ||||||||||||||||||
Issuance of restricted units | 9,478 | 177 | — | (9,480 | ) | — | 175 | |||||||||||||||||
Forfeiture of restricted units | (2,663 | ) | (38 | ) | — | 2,361 | — | (340 | ) | |||||||||||||||
Amortization of Employee Partnership awards | 1,358 | 28 | — | — | — | 1,386 | ||||||||||||||||||
Amortization of deferred compensation | — | — | — | 3,373 | — | 3,373 | ||||||||||||||||||
Cancellation of treasury units | (8,915 | ) | (182 | ) | 8,660 | — | — | (437 | ) | |||||||||||||||
Cash flow hedges | — | — | — | — | (5,482 | ) | (5,482 | ) | ||||||||||||||||
Balance, December 31, 2005 | 5,561,338 | 113,496 | — | (14,597 | ) | 19,072 | 5,679,309 | |||||||||||||||||
Net income | 504,156 | 96,999 | — | — | — | 601,155 | ||||||||||||||||||
Operating leases paid by EPCO, Inc. | 2,067 | 42 | — | — | — | 2,109 | ||||||||||||||||||
Cash distributions to partners | (739,632 | ) | (101,805 | ) | — | — | — | (841,437 | ) | |||||||||||||||
Unit option reimbursements to EPCO, Inc. | (1,818 | ) | (41 | ) | — | — | — | (1,859 | ) | |||||||||||||||
Net proceeds from sales of common units | 830,825 | 16,943 | — | — | — | 847,768 | ||||||||||||||||||
Common units issued to Lewis in connection with Encinal acquisition | 181,112 | 3,705 | — | — | — | 184,817 | ||||||||||||||||||
Proceeds from exercise of unit options | 5,601 | 114 | — | — | — | 5,715 | ||||||||||||||||||
Change in accounting method for equity awards (see Note 5) | (15,815 | ) | (307 | ) | — | 14,597 | — | (1,525 | ) | |||||||||||||||
Change in funded status of pension and postretirement plans, net of tax | — | — | — | — | (464 | ) | (464 | ) | ||||||||||||||||
Amortization of equity awards | 8,282 | 155 | — | — | — | 8,437 | ||||||||||||||||||
Foreign currency translation adjustment | — | — | — | — | (807 | ) | (807 | ) | ||||||||||||||||
Acquisition-related disbursement of cash (see Note 17) | (6,199 | ) | (126 | ) | — | — | — | (6,325 | ) | |||||||||||||||
Cash flow hedges | — | — | — | — | 3,340 | 3,340 | ||||||||||||||||||
Balance, December 31, 2006 | $ | 6,329,917 | $ | 129,175 | $ | — | $ | — | $ | 21,141 | $ | 6,480,233 | ||||||||||||
F-7
Table of Contents
F-8
Table of Contents
F-9
Table of Contents
F-10
Table of Contents
SFAS 123(R).
For the Year Ended December 31, | ||||||||
2005 | 2004 | |||||||
Reported net income | $ | 419,508 | $ | 268,261 | ||||
Additional compensation expense that would have been recorded for unit options | (708 | ) | (932 | ) | ||||
Reduction in compensation expense related to awards of profits interests in EPE Unit L.P. | 1,271 | — | ||||||
Pro forma net income | $ | 420,071 | $ | 267,329 | ||||
Basic and Diluted earnings per unit: | ||||||||
As reported | $ | 0.91 | $ | 0.87 | ||||
Pro forma | $ | 0.91 | $ | 0.87 | ||||
F-11
Table of Contents
F-12
Table of Contents
F-13
Table of Contents
F-14
Table of Contents
F-15
Table of Contents
F-16
Table of Contents
F-17
Table of Contents
F-18
Table of Contents
F-19
Table of Contents
F-20
Table of Contents
Weighted- | ||||||||||||||||
Weighted- | average | |||||||||||||||
average | remaining | Aggregate | ||||||||||||||
Number of | strike price | contractual | Intrinsic | |||||||||||||
Units | (dollars/unit) | term (in years) | Value(1) | |||||||||||||
Outstanding at December 31, 2003 | 1,938,000 | $ | 16.07 | |||||||||||||
Granted(2) | 910,000 | 22.17 | ||||||||||||||
Exercised | (385,000 | ) | 12.79 | |||||||||||||
Outstanding at December 31, 2004 | 2,463,000 | 18.84 | ||||||||||||||
Granted(3) | 530,000 | 26.49 | ||||||||||||||
Exercised | (826,000 | ) | 14.77 | |||||||||||||
Forfeited | (85,000 | ) | 24.73 | |||||||||||||
Outstanding at December 31, 2005 | 2,082,000 | 22.16 | ||||||||||||||
Granted(4) | 590,000 | 24.85 | ||||||||||||||
Exercised | (211,000 | ) | 15.95 | |||||||||||||
Forfeited | (45,000 | ) | 24.28 | |||||||||||||
Outstanding at December 31, 2006 | 2,416,000 | 23.32 | 7.61 | $ | 4,808 | |||||||||||
Options exercisable at: | ||||||||||||||||
December 31, 2004 | 1,154,000 | $ | 14.65 | 6.18 | $ | 13,768 | ||||||||||
December 31, 2005 | 727,000 | $ | 19.19 | 5.54 | $ | 3,503 | ||||||||||
December 31, 2006 | 591,000 | $ | 20.85 | 5.11 | $ | 4,808 | ||||||||||
(1) | Aggregate intrinsic value reflects fully vested unit options at December 31, 2006. | |
(2) | The total grant date fair value of these awards was $2.1 million based on the following assumptions: (i) expected life of options of seven years; (ii) risk-free interest rate of 4.0%; (iii) expected distribution yield on our units of 8.8%; and (iv) expected unit price volatility of 28.6%. | |
(3) | The total grant date fair value of these awards was $0.7 million based on the following assumptions: (i) expected life of options of seven years; (ii) risk-free interest rate of 4.2%; (iii) expected distribution yield on our units of 9.2%; and (iv) expected unit price volatility of 20.0%. | |
(4) | The total grant date fair value of these awards was $1.2 million based on the following assumptions: (i) expected life of options of seven years; (ii) risk-free interest rate of 5.0%; (iii) expected distribution yield on our units of 8.9%; and (iv) expected unit price volatility of 23.5%. |
F-21
Table of Contents
Weighted- | ||||||||
Average Grant | ||||||||
Number of | Date Fair Value | |||||||
Units | per Unit(1) | |||||||
Restricted units at January 1, 2004 | ||||||||
Granted(2) | 488,525 | $ | 22.89 | |||||
Restricted units at December 31, 2004 | 488,525 | |||||||
Granted(3) | 362,011 | $ | 26.43 | |||||
Vested | (6,484 | ) | $ | 22.00 | ||||
Forfeited | (92,448 | ) | $ | 24.03 | ||||
Restricted units at December 31, 2005 | 751,604 | |||||||
Granted(4) | 466,400 | $ | 25.21 | |||||
Vested | (42,136 | ) | $ | 24.02 | ||||
Forfeited | (70,631 | ) | $ | 22.86 | ||||
Restricted units at December 31, 2006 | 1,105,237 | |||||||
(1) | Determined by dividing the aggregate grant date fair value of awards (before allowance for forfeitures) by the number of awards issued | |
(2) | Aggregate grant date fair value of restricted unit awards issued during 2004 was $10.3 million based on grant date market prices of our common units ranging from $20.95 to $23.31 per unit and an estimated forfeiture rate of 8.2%. | |
(3) | Aggregate grant date fair value of restricted unit awards issued during 2005 was $8.8 million based on grant date market prices of our common units ranging from $25.83 to $26.95 per unit and an estimated forfeiture rate of 8.2%. | |
(4) | Aggregate grant date fair value of restricted unit awards issued during 2006 was $10.8 million based on grant date market prices of our common units ranging from $24.85 to $27.45 per unit and estimated forfeiture rates ranging from 7.8% to 9.8%. |
F-22
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F-23
Table of Contents
Pension | Postretirement | |||||||
Plan | Plan | |||||||
Projected benefit obligation | $ | 9,006 | $ | 5,311 | ||||
Accumulated benefit obligation | 6,625 | 5,311 | ||||||
Fair value of plan assets | 7,731 | — | ||||||
Unfunded liability | 1,274 | 5,311 | ||||||
Accrued benefit liability | 1,186 | 5,311 |
Pension | Postretirement | |||||||
Plan | Plan | |||||||
2007 | $ | 621 | $ | 333 | ||||
2008 | 526 | 331 | ||||||
2009 | 754 | 357 | ||||||
2010 | 765 | 395 | ||||||
2011 | 883 | 433 | ||||||
2012 through 2015 | 5,408 | 2,168 | ||||||
Total | $ | 8,957 | $ | 4,017 | ||||
F-24
Table of Contents
At December 31, 2006 | ||||||||||||
Prior to | Effect of | |||||||||||
Adopting | Adopting | |||||||||||
SFAS 158 | SFAS 158 | As reported | ||||||||||
Liability for Dixie benefit plans | $ | 6,404 | $ | 751 | $ | 7,155 | ||||||
Deferred income taxes | — | (287 | ) | (287 | ) | |||||||
Total liabilities | 7,509,021 | 464 | 7,509,485 | |||||||||
Accumulated other comprehensive income | — | (464 | ) | (464 | ) | |||||||
Total equity | 6,480,697 | (464 | ) | 6,480,233 |
F-25
Table of Contents
Number | Period Covered | Termination | Fixed to | Notional | ||||||||
Hedged Fixed Rate Debt | Of Swaps | by Swap | Date of Swap | Variable Rate(1) | Amount | |||||||
Senior Notes B, 7.50% fixed rate, due Feb. 2011 | 1 | Jan. 2004 to Feb. 2011 | Feb. 2011 | 7.50%to 8.89% | $50 million | |||||||
Senior Notes C, 6.375% fixed rate, due Feb. 2013 | 2 | Jan. 2004 to Feb. 2013 | Feb. 2013 | 6.38% to7.43% | $200 million | |||||||
Senior Notes G, 5.6% fixed rate, due Oct. 2014 | 6 | 4th Qtr. 2004 to Oct. 2014 | Oct. 2014 | 5.60% to 6.33% | $600 million | |||||||
Senior Notes K, 4.95% fixed rate, due June 2010 | 2 | Aug. 2005 to June 2010 | June 2010 | 4.95%to 5.76% | $200 million |
(1) | The variable rate indicated is the all-in variable rate for the current settlement period. |
F-26
Table of Contents
Notional | Net Cash | |||||||
Amount of | Received upon | |||||||
Debt covered by | Settlement of | |||||||
Forward | Forward | |||||||
Term of Anticipated Debt Offering(or Forecasted Transaction) | Starting Swaps | Starting Swaps | ||||||
3-year, fixed rate debt instrument | $ | 500,000 | $ | 4,613 | ||||
5-year, fixed rate debt instrument | 500,000 | 7,213 | ||||||
10-year, fixed rate debt instrument | 650,000 | 10,677 | ||||||
30-year, fixed rate debt instrument | 350,000 | (3,098 | ) | |||||
Total | $ | 2,000,000 | $ | 19,405 | ||||
F-27
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F-28
Table of Contents
At December 31, 2006 | At December 31, 2005 | |||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Financial Instruments | Value | Value | Value | Value | ||||||||||||
Financial assets: | ||||||||||||||||
Cash and cash equivalents | $ | 46,286 | $ | 46,286 | $ | 57,050 | $ | 57,050 | ||||||||
Accounts receivable | 1,323,028 | 1,323,028 | 1,454,583 | 1,454,583 | ||||||||||||
Commodity financial instruments(1) | 1,472 | 1,472 | 1,114 | 1,114 | ||||||||||||
Financial liabilities: | ||||||||||||||||
Accounts payable and accrued expenses | 1,774,976 | 1,774,976 | 1,763,390 | 1,763,390 | ||||||||||||
Fixed-rate debt (principal amount) | 4,909,068 | 4,955,176 | 4,359,068 | 4,395,110 | ||||||||||||
Variable-rate debt | 420,000 | 420,000 | 507,000 | 507,000 | ||||||||||||
Commodity financial instruments(1) | 4,655 | 4,655 | 1,167 | 1,167 | ||||||||||||
Interest rate hedging financial instruments(2) | 29,060 | 29,060 | 19,179 | 19,179 |
(1) | Represent commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. | |
(2) | Represent interest rate hedging financial instrument transactions that have not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. |
F-29
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F-30
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Pro Forma income statement amounts: | ||||||||||||
Historical net income | $ | 601,155 | $ | 419,508 | $ | 268,261 | ||||||
Adjustments to derive pro forma net income: | ||||||||||||
Effect of implementation of SFAS 123(R): | ||||||||||||
Remove cumulative effect of change in accounting principle recorded in January 2006 | (1,472 | ) | — | — | ||||||||
Additional compensation expense that would have been recorded for unit options | — | (708 | ) | (932 | ) | |||||||
Remove compensation expense related to awards of profits interests in EPE Unit L.P. | — | 1,271 | — | |||||||||
Effect of implementation of FIN 47: | ||||||||||||
Remove cumulative effect of change in accounting principle recorded in December 2005 | — | 4,208 | — | |||||||||
Record depreciation and accretion expense associated with conditional asset retirement obligations | — | (735 | ) | (373 | ) | |||||||
Effect of change from the accrue-in-advance method to the expense-as-incurred method for BEF major maintenance costs: | ||||||||||||
Remove cumulative effect of change in accounting principle recorded in January 2004 | — | — | (7,013 | ) | ||||||||
Remove minority interest expense associated with change in accounting principle — Sun 33.33% portion | — | — | 2,338 | |||||||||
Effect of changing from the cost method to the equity method with respect to our investment in VESCO: | ||||||||||||
Remove cumulative effect of change in accounting principle recorded in July 2004 | — | — | (3,768 | ) | ||||||||
Remove historical dividend income recorded from VESCO | — | — | (2,136 | ) | ||||||||
Record equity earnings from VESCO | — | — | 2,429 | |||||||||
Pro forma net income | 599,683 | 423,544 | 258,806 | |||||||||
Enterprise Products GP interest | (96,969 | ) | (71,077 | ) | (36,919 | ) | ||||||
Pro forma net income available to limited partners | $ | 502,714 | $ | 352,467 | $ | 221,887 | ||||||
Pro forma per unit data (basic): | ||||||||||||
Historical units outstanding | 414,442 | 382,463 | 265,511 | |||||||||
Per unit data: | ||||||||||||
As reported | $ | 1.22 | $ | 0.91 | $ | 0.87 | ||||||
Pro forma | $ | 1.21 | $ | 0.92 | $ | 0.84 | ||||||
Pro forma per unit data (diluted): | ||||||||||||
Historical units outstanding | 414,759 | 382,963 | 266,045 | |||||||||
Per unit data: | ||||||||||||
As reported | $ | 1.22 | $ | 0.91 | $ | 0.87 | ||||||
Pro forma | $ | 1.21 | $ | 0.92 | $ | 0.83 | ||||||
At December 31, | ||||||||
2006 | 2005 | |||||||
Working inventory | $ | 387,973 | $ | 279,237 | ||||
Forward-sales inventory | 35,871 | 60,369 | ||||||
Inventory | $ | 423,844 | $ | 339,606 | ||||
F-31
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• | Write-downs of NGL inventories are recorded as a cost of our NGL marketing activities within our NGL Pipelines & Services business segment; | ||
• | Write-downs of natural gas inventories are recorded as a cost of our natural gas pipeline operations within our Onshore Natural Gas Pipelines & Services business segment; and | ||
• | Write-downs of petrochemical inventories are recorded as a cost of our petrochemical marketing activities or octane additive production business within our Petrochemical Services business segment, as applicable. |
F-32
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Estimated | ||||||||||||
Useful Life | At December 31, | |||||||||||
in Years | 2006 | 2005 | ||||||||||
Plants and pipelines(1) | 3-35 | (5) | $ | 8,774,683 | $ | 8,209,580 | ||||||
Underground and other storage facilities(2) | 5-35 | (6) | 596,649 | 549,923 | ||||||||
Platforms and facilities(3) | 23-31 | 161,839 | 161,807 | |||||||||
Transportation equipment(4) | 3-10 | 27,008 | 24,939 | |||||||||
Land | 40,010 | 38,757 | ||||||||||
Construction in progress | 1,734,083 | 854,595 | ||||||||||
Total | 11,334,272 | 9,839,601 | ||||||||||
Less accumulated depreciation | 1,501,725 | 1,150,577 | ||||||||||
Property, plant and equipment, net | $ | 9,832,547 | $ | 8,689,024 | ||||||||
(1) | Plants and pipelines include processing plants; NGL, petrochemical, oil and natural gas 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; storage tanks; water wells; and related assets. | |
(3) | Platforms and facilities include offshore platforms and related facilities and other associated assets. | |
(4) | Transportation equipment includes vehicles and similar assets used in our operations. | |
(5) | In general, the estimated useful lives of major components of this category are as follows: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings 20-35 years; and laboratory and shop equipment, 5-35 years. | |
(6) | In general, the estimated useful lives of major components of this category are as follows: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years). |
F-33
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Asset retirement obligation liability balance, December 31, 2005 | $ | 16,795 | ||
Liabilities incurred | 1,977 | |||
Liabilities settled | (1,348 | ) | ||
Revisions in estimated cash flows | 5,650 | |||
Accretion expense | 1,329 | |||
Asset retirement obligation liability balance, December 31, 2006 | $ | 24,403 | ||
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Ownership | Investments in and advances to | |||||||||||
Percentage at | Unconsolidated Affiliates at | |||||||||||
December 31, | December 31, | December 31, | ||||||||||
2006 | 2006 | 2005 | ||||||||||
NGL Pipelines & Services: | ||||||||||||
VESCO | 13.1 | % | $ | 39,618 | $ | 39,689 | ||||||
K/D/S Promix, L.L.C. (“Promix”) | 50 | % | 46,140 | 65,103 | ||||||||
Baton Rouge Fractionators LLC (“BRF”) | 32.3 | % | 25,471 | 25,584 | ||||||||
Onshore Natural Gas Pipelines & Services: | ||||||||||||
Jonah Gas Gathering Company (“Jonah”) | 14.4 | % | 120,370 | — | ||||||||
Evangeline(1) | 49.5 | % | 4,221 | 3,151 | ||||||||
Coyote Gas Treating, LLC (“Coyote”) (2) | — | 1,493 | ||||||||||
Offshore Pipelines & Services: | ||||||||||||
Poseidon Oil Pipeline, L.L.C. (“Poseidon”) | 36 | % | 62,324 | 62,918 | ||||||||
Cameron Highway Oil Pipeline Company (“Cameron Highway”) | 50 | % | 60,216 | 58,207 | ||||||||
Deepwater Gateway, L.L.C. (“Deepwater Gateway”) | 50 | % | 117,646 | 115,477 | ||||||||
Neptune(3) | 25.7 | % | 58,789 | 68,085 | ||||||||
Nemo Gathering Company, LLC (“Nemo”) | 33.9 | % | 11,161 | 12,157 | ||||||||
Petrochemical Services: | ||||||||||||
Baton Rouge Propylene Concentrator, LLC (“BRPC”) | 30 | % | 13,912 | 15,212 | ||||||||
La Porte(4) | 50 | % | 4,691 | 4,845 | ||||||||
Total | $ | 564,559 | $ | 471,921 | ||||||||
(1) | Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. | |
(2) | We sold our 50% interest in Coyote in August 2006 and recorded a net gain on the sale of $3.3 million. | |
(3) | In 2006, we recorded a $7.4 million non-cash impairment charge attributable to our investment in Neptune. | |
(4) | Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively. |
F-35
Table of Contents
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
NGL Pipelines & Services: | ||||||||||||
Dixie(1) | $ | — | $ | 1,103 | $ | 1,273 | ||||||
VESCO(2) | 1,719 | 1,412 | 6,132 | |||||||||
Belle Rose(1) | — | (151 | ) | (402 | ) | |||||||
Promix | 1,353 | 1,876 | 859 | |||||||||
BRF | 2,643 | 1,313 | 2,190 | |||||||||
Tri-States(1) | — | — | (154 | ) | ||||||||
Onshore Natural Gas Pipelines & Services: | ||||||||||||
Evangeline | 958 | 331 | 231 | |||||||||
Coyote | 1,676 | 2,053 | 541 | |||||||||
Jonah | 238 | — | — | |||||||||
Offshore Pipelines & Services: | ||||||||||||
Poseidon | 11,310 | 7,279 | 2,509 | |||||||||
Cameron Highway(3) | (11,000 | ) | (15,872 | ) | (461 | ) | ||||||
Deepwater Gateway | 18,392 | 10,612 | 3,562 | |||||||||
Neptune(4) | (8,294 | ) | 2,019 | (1,852 | ) | |||||||
Nemo | 1,501 | 1,774 | 1,628 | |||||||||
Starfish Pipeline Company, LLC (“Starfish”)(5) | — | 313 | 3,473 | |||||||||
Petrochemical Services: | ||||||||||||
BRPC | 1,864 | 1,224 | 1,943 | |||||||||
La Porte | (795 | ) | (738 | ) | (710 | ) | ||||||
Other: | ||||||||||||
GulfTerra GP(6) | — | — | 32,025 | |||||||||
Total | $ | 21,565 | $ | 14,548 | $ | 52,787 | ||||||
(1) | We acquired additional ownership interests in or control over these entities since January 1, 2004 resulting in our consolidation of each company’s post-acquisition financial results with those of our own. Our consolidation of each company’s post-acquisition financial results began in the following periods: Dixie, February 2005; Belle Rose, June 2005; and Tri-States, April 2004. | |
(2) | As a result of adopting EITF 03-16 during 2004, we changed from the cost method to the equity method of accounting with respect to our investment in VESCO. See Note 8. | |
(3) | Equity earnings from Cameron Highway for the year ended December 31, 2005 were reduced by a charge of $11.5 million for costs associated with the refinancing of Cameron Highway’s project debt (see Note 14). | |
(4) | Equity earnings from Neptune for 2006 include a $7.4 million non-cash impairment charge. | |
(5) | We were required under a consent decree published for comment by the U.S. Federal Trade Commission on September 30, 2004 to sell our 50% interest in Starfish. On March 31, 2005, we sold this asset to a third-party. | |
(6) | In connection with the GulfTerra Merger (see Note 12), GulfTerra GP became a wholly owned consolidated subsidiary of ours on September 30, 2004. We had previously accounted for our 50% ownership interest in GulfTerra GP as an equity method investment from December 15, 2003 through September 29, 2004. |
F-36
Table of Contents
At December 31, | ||||||||
2006 | 2005 | |||||||
BALANCE SHEET DATA: | ||||||||
Current assets | $ | 62,138 | $ | 72,784 | ||||
Property, plant and equipment, net | 242,083 | 328,270 | ||||||
Other assets | 12,189 | 12,471 | ||||||
Total assets | $ | 316,410 | $ | 413,525 | ||||
Current liabilities | $ | 30,686 | $ | 32,886 | ||||
Other liabilities | 8,117 | 7,343 | ||||||
Combined equity | 277,607 | 373,296 | ||||||
Total liabilities and combined equity | $ | 316,410 | $ | 413,525 | ||||
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
INCOME STATEMENT DATA: | ||||||||||||
Revenues | $ | 190,320 | $ | 207,775 | $ | 244,521 | ||||||
Operating income (loss) | (26,885 | ) | 6,696 | 40,259 | ||||||||
Net income (loss) | (25,543 | ) | 6,509 | 40,355 |
F-37
Table of Contents
At December 31, | ||||||||
2006 | 2005 | |||||||
BALANCE SHEET DATA: | ||||||||
Current assets | $ | 65,048 | $ | 36,118 | ||||
Property, plant and equipment, net | 639,641 | 36,380 | ||||||
Other assets | 192,027 | 33,950 | ||||||
Total assets | $ | 896,716 | $ | 106,448 | ||||
Current liabilities | $ | 49,708 | $ | 72,498 | ||||
Other liabilities | 28,802 | 32,737 | ||||||
Combined equity | 818,206 | 1,213 | ||||||
Total liabilities and combined equity | $ | 896,716 | $ | 106,448 | ||||
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
INCOME STATEMENT DATA: | ||||||||||||
Revenues | $ | 372,240 | $ | 347,561 | $ | 257,957 | ||||||
Operating income | 48,387 | 9,142 | 8,971 | |||||||||
Net income | 40,608 | 4,668 | 4,657 |
F-38
Table of Contents
At December 31, | ||||||||
2006 | 2005 | |||||||
BALANCE SHEET DATA: | ||||||||
Current assets | $ | 56,689 | $ | 141,756 | ||||
Property, plant and equipment, net | 1,178,811 | 1,201,926 | ||||||
Other assets | 10,108 | 7,961 | ||||||
Total assets | $ | 1,245,608 | $ | 1,351,643 | ||||
Current liabilities | $ | 22,043 | $ | 120,611 | ||||
Other liabilities | 510,773 | 511,633 | ||||||
Combined equity | 712,792 | 719,399 | ||||||
Total liabilities and combined equity | $ | 1,245,608 | $ | 1,351,643 | ||||
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
INCOME STATEMENT DATA: | ||||||||||||
Revenues | $ | 153,996 | $ | 154,297 | $ | 88,603 | ||||||
Operating income | 71,977 | 78,027 | 46,938 | |||||||||
Net income | 42,732 | 29,086 | 38,473 |
F-39
Table of Contents
At December 31, | ||||||||
2006 | 2005 | |||||||
BALANCE SHEET DATA: | ||||||||
Current assets | $ | 3,324 | $ | 5,508 | ||||
Property, plant and equipment, net | 51,159 | 54,751 | ||||||
Total assets | $ | 54,483 | $ | 60,259 | ||||
Current liabilities | $ | 832 | $ | 1,178 | ||||
Other liabilities | 2 | 1 | ||||||
Combined equity | 53,649 | 59,080 | ||||||
Total liabilities and combined equity | $ | 54,483 | $ | 60,259 | ||||
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
INCOME STATEMENT DATA: | ||||||||||||
Revenues | $ | 19,014 | $ | 16,849 | $ | 18,378 | ||||||
Operating income | 4,626 | 2,606 | 5,131 | |||||||||
Net income | 4,729 | 2,650 | 5,151 |
F-40
Table of Contents
For Year Ended | ||||
December 31, | ||||
2004 | ||||
Pro forma earnings data: | ||||
Revenues | $ | 9,615 | ||
Costs and expenses | $ | 9,067 | ||
Operating income | $ | 576 | ||
Net income | $ | 335 | ||
Basic earnings per unit (“EPU”): | ||||
Units outstanding, as reported | 265 | |||
Units outstanding , pro forma | 378 | |||
Basic EPU, as reported | $ | 0.87 | ||
Basic EPU, pro forma | $ | 0.75 | ||
Diluted EPU: | ||||
Units outstanding, as reported | 266 | |||
Units outstanding , pro forma | 379 | |||
Diluted EPU, as reported | $ | 0.87 | ||
Diluted EPU, pro forma | $ | 0.75 | ||
F-41
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F-42
Table of Contents
Cash payment to Lewis | $ | 145,197 | ||
Fair value of our 7,115,844 common units issued to Lewis | 181,112 | |||
Total consideration | $ | 326,309 | ||
For the Year Ended December 31, | ||||||||
2006 | 2005 | |||||||
Pro forma earnings data: | ||||||||
Revenues | $ | 14,066 | $ | 12,408 | ||||
Costs and expenses | $ | 13,228 | $ | 11,758 | ||||
Operating income | $ | 859 | $ | 664 | ||||
Net income | $ | 598 | $ | 418 | ||||
Basic earnings per unit (“EPU”): | ||||||||
Units outstanding, as reported | 414 | 382 | ||||||
Units outstanding , pro forma | 422 | 389 | ||||||
Basic EPU, as reported | $ | 1.22 | $ | 0.91 | ||||
Basic EPU, pro forma | $ | 1.19 | $ | 0.89 | ||||
Diluted EPU: | ||||||||
Units outstanding, as reported | 415 | 383 | ||||||
Units outstanding , pro forma | 422 | 390 | ||||||
Diluted EPU, as reported | $ | 1.22 | $ | 0.91 | ||||
Diluted EPU, pro forma | $ | 1.19 | $ | 0.89 | ||||
F-43
Table of Contents
Piceance | ||||||||||||||||
Encinal | Creek | |||||||||||||||
Acquisition | Acquisition | Other | Total | |||||||||||||
Assets acquired in business combination: | ||||||||||||||||
Current assets | $ | 218 | $ | — | $ | 36,080 | $ | 36,298 | ||||||||
Property, plant and equipment, net | 100,310 | 91,540 | 12,369 | 204,219 | ||||||||||||
Investments in and advances to unconsolidated affiliates | — | — | — | — | ||||||||||||
Intangible assets | 132,872 | 8,460 | — | 141,332 | ||||||||||||
Other assets | — | — | — | — | ||||||||||||
Total assets acquired | 233,400 | 100,000 | 48,449 | 381,849 | ||||||||||||
Liabilities assumed in business combination: | ||||||||||||||||
Current liabilities | (2,149 | ) | — | (18,836 | ) | (20,985 | ) | |||||||||
Long-term debt | — | — | — | — | ||||||||||||
Other long-term liabilities | (108 | ) | — | (175 | ) | (283 | ) | |||||||||
Minority interest | — | — | 1,865 | 1,865 | ||||||||||||
Total liabilities assumed | (2,257 | ) | — | (17,146 | ) | (19,403 | ) | |||||||||
Total assets acquired less liabilities assumed | 231,143 | 100,000 | 31,303 | 362,446 | ||||||||||||
Total consideration given | 326,309 | 100,000 | 31,303 | 457,612 | ||||||||||||
Goodwill | $ | 95,166 | $ | — | $ | — | $ | 95,166 | ||||||||
F-44
Table of Contents
At December 31, 2006 | At December 31, 2005 | |||||||||||||||||||||||
Gross | Accum. | Carrying | Gross | Accum. | Carrying | |||||||||||||||||||
Value | Amort. | Value | Value | Amort. | Value | |||||||||||||||||||
NGL Pipelines & Services: | ||||||||||||||||||||||||
Shell Processing Agreement | $ | 206,216 | $ | (67,204 | ) | $ | 139,012 | $ | 206,216 | $ | (56,157 | ) | $ | 150,059 | ||||||||||
Encinal gas processing customer relationship | 127,119 | (6,049 | ) | 121,070 | — | — | — | |||||||||||||||||
STMA and GulfTerra NGL Business customer relationships(1) | 49,784 | (12,980 | ) | 36,804 | 49,784 | (7,829 | ) | 41,955 | ||||||||||||||||
Pioneer gas processing contracts | 37,752 | — | 37,752 | — | — | — | ||||||||||||||||||
Markham NGL storage contracts(1) | 32,664 | (9,800 | ) | 22,864 | 32,664 | (5,444 | ) | 27,220 | ||||||||||||||||
Toca-Western contracts | 31,229 | (7,156 | ) | 24,073 | 31,229 | (5,595 | ) | 25,634 | ||||||||||||||||
Piceance Creek customer relationship | 8,460 | — | 8,460 | — | — | — | ||||||||||||||||||
Other | 35,370 | (7,455 | ) | 27,915 | 35,370 | (4,460 | ) | 30,910 | ||||||||||||||||
Segment total | 528,594 | (110,644 | ) | 417,950 | 355,263 | (79,485 | ) | 275,778 | ||||||||||||||||
Onshore Natural Gas Pipelines & Services: | ||||||||||||||||||||||||
San Juan Gathering System customer relationships(1) | 331,311 | (52,318 | ) | 278,993 | 331,311 | (30,065 | ) | 301,246 | ||||||||||||||||
Petal & Hattiesburg natural gas storage contracts(1) | 100,499 | (19,337 | ) | 81,162 | 100,499 | (10,742 | ) | 89,757 | ||||||||||||||||
Other | 31,741 | (5,747 | ) | 25,994 | 25,988 | (3,148 | ) | 22,840 | ||||||||||||||||
Segment total | 463,551 | (77,402 | ) | 386,149 | 457,798 | (43,955 | ) | 413,843 | ||||||||||||||||
Offshore Pipelines & Services: | ||||||||||||||||||||||||
Offshore pipeline & platform customer relationships(1) | 205,845 | (54,636 | ) | 151,209 | 205,845 | (32,480 | ) | 173,365 | ||||||||||||||||
Other | 1,167 | — | 1,167 | 1,167 | — | 1,167 | ||||||||||||||||||
Segment total | 207,012 | (54,636 | ) | 152,376 | 207,012 | (32,480 | ) | 174,532 | ||||||||||||||||
Petrochemical Services: | ||||||||||||||||||||||||
Mont Belvieu propylene fractionation contracts | 53,000 | (7,445 | ) | 45,555 | 53,000 | (5,931 | ) | 47,069 | ||||||||||||||||
Other | 3,674 | (1,749 | ) | 1,925 | 3,674 | (1,270 | ) | 2,404 | ||||||||||||||||
Segment total | 56,674 | (9,194 | ) | 47,480 | 56,674 | (7,201 | ) | 49,473 | ||||||||||||||||
Total all segments | $ | 1,255,831 | $ | (251,876 | ) | $ | 1,003,955 | $ | 1,076,747 | $ | (163,121 | ) | $ | 913,626 | ||||||||||
(1) | Acquired in connection with the GulfTerra Merger and related transactions in September 2004. |
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
NGL Pipelines & Services | $ | 31,159 | $ | 26,350 | $ | 16,000 | ||||||
Onshore Natural Gas Pipelines & Services | 33,447 | 35,080 | 8,875 | |||||||||
Offshore Pipelines & Services | 22,156 | 25,515 | 6,965 | |||||||||
Petrochemical Services | 1,993 | 1,993 | 1,973 | |||||||||
Total all segments | $ | 88,755 | $ | 88,938 | $ | 33,813 | ||||||
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At December 31, | ||||||||
2006 | 2005 | |||||||
NGL Pipelines & Services | ||||||||
GulfTerra Merger | $ | 23,854 | $ | 23,927 | ||||
Acquisition of Indian Springs natural gas processing business | 13,162 | 13,180 | ||||||
Encinal acquisition | 95,166 | — | ||||||
Other | 20,413 | 17,853 | ||||||
Onshore Natural Gas Pipelines & Services | ||||||||
GulfTerra Merger | 279,956 | 280,812 | ||||||
Acquisition of Indian Springs natural gas gathering business | 2,165 | 2,185 | ||||||
Offshore Pipelines & Services | ||||||||
GulfTerra Merger | 82,135 | 82,386 | ||||||
Petrochemical Services | ||||||||
Acquisition of Mont Belvieu propylene fractionation business | 73,690 | 73,690 | ||||||
Total | $ | 590,541 | $ | 494,033 | ||||
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At December 31, | ||||||||
2006 | 2005 | |||||||
Operating Partnership senior debt obligations: | ||||||||
Multi-Year Revolving Credit Facility, variable rate, due October 2011(1) | $ | 410,000 | $ | 490,000 | ||||
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 | 54,000 | 54,000 | ||||||
Senior Notes B, 7.50% fixed-rate, due February 2011 | 450,000 | 450,000 | ||||||
Senior Notes C, 6.375% fixed-rate, due February 2013 | 350,000 | 350,000 | ||||||
Senior Notes D, 6.875% fixed-rate, due March 2033 | 500,000 | 500,000 | ||||||
Senior Notes E, 4.00% fixed-rate, due October 2007(2) | 500,000 | 500,000 | ||||||
Senior Notes F, 4.625% fixed-rate, due October 2009 | 500,000 | 500,000 | ||||||
Senior Notes G, 5.60% fixed-rate, due October 2014 | 650,000 | 650,000 | ||||||
Senior Notes H, 6.65% fixed-rate, due October 2034 | 350,000 | 350,000 | ||||||
Senior Notes I, 5.00% fixed-rate, due March 2015 | 250,000 | 250,000 | ||||||
Senior Notes J, 5.75% fixed-rate, due March 2035 | 250,000 | 250,000 | ||||||
Senior Notes K, 4.950% fixed-rate, due June 2010 | 500,000 | 500,000 | ||||||
Dixie Revolving Credit Facility, variable rate, due June 2010 | 10,000 | 17,000 | ||||||
Other, 8.75% fixed-rate, due June 2010(3) | 5,068 | 5,068 | ||||||
Total principal amount of senior debt obligations | 4,779,068 | 4,866,068 | ||||||
Operating Partnership Junior Subordinated Notes A, due August 2066 | 550,000 | — | ||||||
Total principal amount of senior and junior debt obligations | 5,329,068 | 4,866,068 | ||||||
Other, including unamortized discounts and premiums and changes in fair value(4) | (33,478 | ) | (32,287 | ) | ||||
Long-term debt | $ | 5,295,590 | $ | 4,833,781 | ||||
Standby letters of credit outstanding | $ | 49,858 | $ | 33,129 | ||||
(1) | In June 2006, the Operating Partnership executed a second amendment (the “Second Amendment”) to the credit agreement governing its Multi-Year Revolving Credit Facility. The Second Amendment, among other things, extends the maturity date of amounts borrowed under the Multi-Year Revolving Credit Facility from October 2010 to October 2011 with respect to $1.25 billion of the commitments. Borrowings with respect to the remaining $48.0 million in commitments mature in October 2010. | |
(2) | In accordance with SFAS 6, “Classification of Short-Term Obligations Expected to be Refinanced,” long-term and current maturities of debt reflects the classification of such obligations at December 31, 2006. With respect to Senior Notes E due in October 2007, the Operating Partnership has the ability to use available credit capacity under its Multi-Year Revolving Credit Facility to fund the repayment of this debt. | |
(3) | Represents remaining debt obligations assumed in connection with the GulfTerra Merger. | |
(4) | The December 31, 2006 amount includes $29.1 million related to fair value hedges and a net $4.4 million in unamortized discounts and premiums. The December 31, 2005 amount includes $19.2 million related to fair value hedges and a net $13.1 million in unamortized discounts and premiums. |
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Range of | Weighted-average | |||||||
interest rates | interest rate | |||||||
paid | paid | |||||||
Operating Partnership’s Multi-Year Revolving Credit Facility | 4.87% to 8.25% | 5.66 | % | |||||
Dixie Revolving Credit Facility | 4.67% to 5.79% | 5.36 | % |
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2007 | $ | — | ||
2008 | — | |||
2009 | 500,000 | |||
2010 | 569,068 | |||
2011 | 1,360,000 | |||
Thereafter | 2,900,000 | |||
Total scheduled principal payments | $ | 5,329,068 | ||
Our | Scheduled Maturities of Debt | |||||||||||||||||||||||||||||||
Ownership | After | |||||||||||||||||||||||||||||||
Interest | Total | 2007 | 2008 | 2009 | 2010 | 2011 | 2011 | |||||||||||||||||||||||||
Cameron Highway | 50 | % | $ | 415,000 | $ | — | $ | 25,000 | $ | 25,000 | $ | 50,000 | $ | 55,000 | $ | 260,000 | ||||||||||||||||
Poseidon | 36 | % | 91,000 | — | — | — | — | 91,000 | — | |||||||||||||||||||||||
Evangeline | 49.5 | % | 25,650 | 5,000 | 5,000 | 5,000 | 10,650 | — | — | |||||||||||||||||||||||
Total | $ | 531,650 | $ | 5,000 | $ | 30,000 | $ | 30,000 | $ | 60,650 | $ | 146,000 | $ | 260,000 | ||||||||||||||||||
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Net Proceeds from Sale of Common Units | ||||||||||||||||
Number of | Contributed | Contributed by | Total | |||||||||||||
common units | by Limited | General | Net | |||||||||||||
issued | Partners | Partner | Proceeds | |||||||||||||
Fiscal 2004: | ||||||||||||||||
Underwritten offerings | 34,500,000 | $ | 680,390 | $ | 13,886 | $ | 694,276 | |||||||||
Other offerings, primarily DRIP | 5,183,591 | 109,368 | 2,231 | 111,599 | ||||||||||||
Total 2004 | 39,683,591 | $ | 789,758 | $ | 16,117 | $ | 805,875 | |||||||||
Fiscal 2005: | ||||||||||||||||
Underwritten offerings | 21,250,000 | $ | 544,347 | $ | 11,109 | $ | 555,456 | |||||||||
Other offerings, primarily DRIP | 2,729,740 | 68,269 | 1,393 | 69,662 | ||||||||||||
Total 2005 | 23,979,740 | $ | 612,616 | $ | 12,502 | $ | 625,118 | |||||||||
Fiscal 2006: | ||||||||||||||||
Underwritten offerings | 31,050,000 | $ | 735,819 | $ | 15,003 | $ | 750,822 | |||||||||
Other offerings, primarily DRIP | 3,774,649 | 95,006 | 1,940 | 96,946 | ||||||||||||
Total 2006 | 34,824,649 | $ | 830,825 | $ | 16,943 | $ | 847,768 | |||||||||
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Restricted | Class B | |||||||||||||||
Common | Common | Special | Treasury | |||||||||||||
Units | Units | Units | Units | |||||||||||||
Balance, December 31, 2003 | 213,366,760 | — | 4,413,549 | 798,313 | ||||||||||||
Units issued in connection with underwritten offerings | 34,500,000 | — | — | — | ||||||||||||
Units issued in connection with other offerings | 5,200,078 | |||||||||||||||
Units issued in connection with equity-based awards | — | 434,225 | — | — | ||||||||||||
Reissuance of treasury units to satisfy exercise of options | 371,113 | — | — | (371,113 | ) | |||||||||||
Conversion of Class B special units to common units | 4,413,549 | — | (4,413,549 | ) | — | |||||||||||
Units issued in connection with GulfTerra Merger (see Note 12) | 104,495,523 | 54,300 | — | — | ||||||||||||
Conversion of Series F2 units to common units | 1,950,317 | — | — | — | ||||||||||||
Balance, December 31, 2004 | 364,297,340 | 488,525 | — | 427,200 | ||||||||||||
Units issued in connection with underwritten offerings | 21,250,000 | — | — | — | ||||||||||||
Units issued in connection with other offerings | 2,729,740 | — | — | — | ||||||||||||
Units issued in connection with equity-based awards | 826,000 | 362,011 | — | — | ||||||||||||
Forfeiture of restricted units | — | (92,448 | ) | — | — | |||||||||||
Conversion of restricted units to common units | 6,484 | (6,484 | ) | — | — | |||||||||||
Cancellation of treasury units | — | — | — | (427,200 | ) | |||||||||||
Balance, December 31, 2005 | 389,109,564 | 751,604 | — | — | ||||||||||||
Units issued in connection with underwritten offerings | 31,050,000 | — | — | — | ||||||||||||
Units issued in connection with other offerings | 3,774,649 | — | — | — | ||||||||||||
Units issued in connection with equity-based awards | 211,000 | 466,400 | — | — | ||||||||||||
Forfeiture of restricted units | — | (70,631 | ) | — | — | |||||||||||
Conversion of restricted units to common units | 42,136 | (42,136 | ) | — | — | |||||||||||
Units issued in connection with Encinal acquisition | 7,115,844 | — | — | — | ||||||||||||
�� | ||||||||||||||||
Balance, December 31, 2006 | 431,303,193 | 1,105,237 | — | — | ||||||||||||
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Restricted | Class B | |||||||||||||||
Common | Common | Special | ||||||||||||||
units | units | units | Total | |||||||||||||
Balance, December 31, 2003 | $ | 1,582,951 | $ | — | $ | 100,182 | $ | 1,683,133 | ||||||||
Net income | 229,016 | 142 | 1,995 | 231,153 | ||||||||||||
Operating leases paid by EPCO | 7,449 | 2 | 100 | 7,551 | ||||||||||||
Cash distributions to partners | (390,928 | ) | (218 | ) | (3,288 | ) | (394,434 | ) | ||||||||
Unit option reimbursements to EPCO | (3,813 | ) | — | — | (3,813 | ) | ||||||||||
Net proceeds from sales of common units | 789,758 | — | — | 789,758 | ||||||||||||
Proceeds from conversion of Series F2 convertible units to common units | 38,800 | — | — | 38,800 | ||||||||||||
Proceeds from exercise of unit options | 398 | — | — | 398 | ||||||||||||
Conversion of Class B special units to common units | 98,993 | — | (98,993 | ) | — | |||||||||||
Value of equity interests granted to complete the GulfTerra Merger | 2,851,796 | 2,479 | — | 2,854,275 | ||||||||||||
Other issuance of restricted units | — | 9,922 | — | 9,922 | ||||||||||||
Treasury units reissued to satisfy unit options | 520 | — | 4 | 524 | ||||||||||||
Balance, December 31, 2004 | 5,204,940 | 12,327 | — | 5,217,267 | ||||||||||||
Net income | 347,948 | 564 | — | 348,512 | ||||||||||||
Operating leases paid by EPCO | 2,067 | 3 | — | 2,070 | ||||||||||||
Cash distributions to partners | (629,629 | ) | (931 | ) | — | (630,560 | ) | |||||||||
Unit option reimbursements to EPCO | (9,199 | ) | — | — | (9,199 | ) | ||||||||||
Net proceeds from sales of common units | 612,616 | — | — | 612,616 | ||||||||||||
Proceeds from exercise of unit options | 21,374 | — | — | 21,374 | ||||||||||||
Issuance of restricted units | — | 9,478 | — | 9,478 | ||||||||||||
Vesting of restricted units | 143 | (143 | ) | — | — | |||||||||||
Forfeiture of restricted units | — | (2,663 | ) | — | (2,663 | ) | ||||||||||
Amortization of equity-based awards | 1,355 | 3 | — | 1,358 | ||||||||||||
Cancellation of treasury units | (8,915 | ) | — | — | (8,915 | ) | ||||||||||
Balance, December 31, 2005 | 5,542,700 | 18,638 | — | 5,561,338 | ||||||||||||
Net income | 502,969 | 1,187 | — | 504,156 | ||||||||||||
Operating leases paid by EPCO | 2,062 | 5 | — | 2,067 | ||||||||||||
Cash distributions to partners | (738,004 | ) | (1,628 | ) | — | (739,632 | ) | |||||||||
Unit option reimbursements to EPCO | (1,818 | ) | — | — | (1,818 | ) | ||||||||||
Net proceeds from sales of common units | 830,825 | — | — | 830,825 | ||||||||||||
Common units issued in connection with Encinal acquisition | 181,112 | — | — | 181,112 | ||||||||||||
Proceeds from exercise of unit options | 5,601 | — | 5,601 | |||||||||||||
Amortization of equity-based awards | 2,209 | 6,073 | — | 8,282 | ||||||||||||
Change in accounting method for equity Awards (see Note 5) | (896 | ) | (14,919 | ) | — | (15,815 | ) | |||||||||
Acquisition-related disbursement of cash | (6,183 | ) | (16 | ) | — | (6,199 | ) | |||||||||
Balance, December 31, 2006 | $ | 6,320,577 | $ | 9,340 | $ | — | $ | 6,329,917 | ||||||||
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GulfTerra units outstanding at September 30, 2004: | ||||
Common units, including time-vested restricted common units | 60,638,989 | |||
Series C units | 10,937,500 | |||
Total historical units outstanding at September 30, 2004 | 71,576,489 | |||
Adjustments to GulfTerra historical units outstanding as a result of the GulfTerra Merger: | ||||
Purchase of GulfTerra Series C units from El Paso | (10,937,500 | ) | ||
Purchase of GulfTerra common units from El Paso | (2,876,620 | ) | ||
GulfTerra common units outstanding subject exchange offer | 57,762,369 | |||
Conversion ratio (1.81 of our common units for each GulfTerra common unit) | 1.81 | |||
Common units issued to GulfTerra common unitholders in connection with GulfTerra Merger (adjusted for fractional common units) | 104,549,823 | |||
Average closing price per unit of our common units immediately prior to and after proposed GulfTerra Merger was announced on December 15, 2003 | $ | 23.39 | ||
Fair value of our common units issued in conversion of remaining GulfTerra common units | $ | 2,445,420 | ||
Fair value of common units issued in conversion of remaining GulfTerra common units | $ | 2,445,420 | ||
Fair value of equity interests issued to acquire the remaining 50% membership interest in GulfTerra GP (voting interest)(1) | 461,347 | |||
Fair value of other equity interests issued for unit awards and Series F2 convertible units | 4,005 | |||
Total value of equity interests issued upon closing of GulfTerra Merger | $ | 2,910,772 | ||
(1) | This fair value is based on 50% of an implied $922.7 million total value for GulfTerra GP, which assumes that the $370.0 million cash payment made by Enterprise Products GP to El Paso in September 2004 represented consideration for a 40.1% interest in GulfTerra GP. The 40.1% interest was derived by deducting the 9.9% membership interest in Enterprise Products GP granted to El Paso in this transaction from the 50% membership interest in GulfTerra GP that Enterprise Products GP acquired from El Paso. The fair value of $461.3 million assigned to this voting membership interest in GulfTerra GP compares favorably to the $425.0 million we paid El Paso in December 2003 to purchase our initial 50% non-voting membership interest in GulfTerra GP. The contribution of this 50% membership interest to Enterprise Products Partners is allocated for financial reporting purposes to our limited partners and general partner based on the respective ownership percentages and the related allocation of profits and losses of 98% and 2%, respectively, both of which are consistent with the Partnership Agreement. |
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• | 2% of quarterly cash distributions up to $0.253 per unit; | ||
• | 15% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit; and | ||
• | 25% of quarterly cash distributions that exceed $0.3085 per unit. |
Distribution | Record | Payment | ||||||||||
per Unit(1) | Date | Date | ||||||||||
2005 | ||||||||||||
1st Quarter | $ | 0.4100 | Apr. 29, 2005 | May 10, 2005 | ||||||||
2nd Quarter | $ | 0.4200 | Jul. 29, 2005 | Aug. 10, 2005 | ||||||||
3rd Quarter | $ | 0.4300 | Oct. 31, 2005 | Nov. 8, 2005 | ||||||||
4th Quarter | $ | 0.4375 | Jan. 31, 2006 | Feb. 9, 2006 | ||||||||
2006 | ||||||||||||
1st Quarter | $ | 0.4450 | Apr. 28, 2006 | May 10, 2006 | ||||||||
2nd Quarter | $ | 0.4525 | Jul. 31, 2006 | Aug. 10, 2006 | ||||||||
3rd Quarter | $ | 0.4600 | Oct. 31, 2006 | Nov. 8, 2006 | ||||||||
4th Quarter | $ | 0.4675 | Jan. 31, 2007 | Feb. 8, 2007 |
(1) | Distributions are paid on common and restricted units, and prior to their conversion to common units, were also paid on Class B special units. |
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Revenues(1) | $ | 13,990,969 | $ | 12,256,959 | $ | 8,321,202 | ||||||
Less: Operating costs and expenses(1) | (13,089,091 | ) | (11,546,225 | ) | (7,904,336 | ) | ||||||
Add: Equity in income of unconsolidated affiliates(1) | 21,565 | 14,548 | 52,787 | |||||||||
Depreciation, amortization and accretion in operating costs and expenses(2) | 440,256 | 413,441 | 193,734 | |||||||||
Operating lease expenses paid by EPCO(2) | 2,109 | 2,112 | 7,705 | |||||||||
Gain on sale of assets in operating costs and expenses(2) | (3,359 | ) | (4,488 | ) | (15,901 | ) | ||||||
Total segment gross operating margin | $ | 1,362,449 | $ | 1,136,347 | $ | 655,191 | ||||||
(1) | These amounts are taken from our Statements of Consolidated Operations. | |
These non-cash expenses are taken from the operating activities section of our Statements of Consolidated Cash Flows. |
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Total segment gross operating margin | $ | 1,362,449 | $ | 1,136,347 | $ | 655,191 | ||||||
Adjustments to reconcile total segment gross operating margin to operating income: | ||||||||||||
Depreciation, amortization and accretion in operating costs and expenses | (440,256 | ) | (413,441 | ) | (193,734 | ) | ||||||
Operating lease expense paid by EPCO | (2,109 | ) | (2,112 | ) | (7,705 | ) | ||||||
Gain on sale of assets in operating costs and expenses | 3,359 | 4,488 | 15,901 | |||||||||
General and administrative costs | (63,391 | ) | (62,266 | ) | (46,659 | ) | ||||||
Consolidated operating income | 860,052 | 663,016 | 422,994 | |||||||||
Other expense, net | (229,967 | ) | (225,178 | ) | (153,625 | ) | ||||||
Income before provision for income taxes, minority interest and cumulative effect of changes in accounting principles | $ | 630,085 | $ | 437,838 | $ | 269,369 | ||||||
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Reportable Segments | ||||||||||||||||||||||||||||
Onshore | ||||||||||||||||||||||||||||
Offshore | Natural Gas | NGL | Adjustments | |||||||||||||||||||||||||
Pipelines | Pipelines | Pipelines | Petrochemical | Non-Segmt. | and | Consolidated | ||||||||||||||||||||||
& Services | & Services | & Services | Services | Other | Eliminations | Totals | ||||||||||||||||||||||
Revenues from third parties: | ||||||||||||||||||||||||||||
Year ended December 31, 2006 | $ | 144,065 | $ | 1,401,486 | $ | 10,079,534 | $ | 1,956,268 | $ | — | $ | — | $ | 13,581,353 | ||||||||||||||
Year ended December 31, 2005 | 110,100 | 1,198,320 | 9,006,730 | 1,587,037 | — | — | 11,902,187 | |||||||||||||||||||||
Year ended December 31, 2004 | 32,168 | 541,529 | 5,553,895 | 1,389,460 | — | — | 7,517,052 | |||||||||||||||||||||
Revenues from related parties: | ||||||||||||||||||||||||||||
Year ended December 31, 2006 | 1,798 | 297,409 | 110,409 | — | — | — | 409,616 | |||||||||||||||||||||
Year ended December 31, 2005 | 696 | 337,282 | 16,689 | 105 | — | — | 354,772 | |||||||||||||||||||||
Year ended December 31, 2004 | 535 | 253,194 | 534,279 | 16,142 | — | — | 804,150 | |||||||||||||||||||||
Intersegment and intrasegment revenues: | ||||||||||||||||||||||||||||
Year ended December 31, 2006 | 1,679 | 113,132 | 4,131,776 | 383,754 | — | (4,630,341 | ) | — | ||||||||||||||||||||
Year ended December 31, 2005 | 1,353 | 41,576 | 3,334,763 | 346,458 | — | (3,724,150 | ) | — | ||||||||||||||||||||
Year ended December 31, 2004 | 358 | 21,436 | 2,077,871 | 249,758 | — | (2,349,423 | ) | — | ||||||||||||||||||||
Total revenues: | ||||||||||||||||||||||||||||
Year ended December 31, 2006 | 147,542 | 1,812,027 | 14,321,719 | 2,340,022 | — | (4,630,341 | ) | 13,990,969 | ||||||||||||||||||||
Year ended December 31, 2005 | 112,149 | 1,577,178 | 12,358,182 | 1,933,600 | — | (3,724,150 | ) | 12,256,959 | ||||||||||||||||||||
Year ended December 31, 2004 | 33,061 | 816,159 | 8,166,045 | 1,655,360 | — | (2,349,423 | ) | 8,321,202 | ||||||||||||||||||||
Equity in income of unconsolidated affiliates: | ||||||||||||||||||||||||||||
Year ended December 31, 2006 | 11,909 | 2,872 | 5,715 | 1,069 | — | — | 21,565 | |||||||||||||||||||||
Year ended December 31, 2005 | 6,125 | 2,384 | 5,553 | 486 | — | — | 14,548 | |||||||||||||||||||||
Year ended December 31, 2004 | 8,859 | 772 | 9,898 | 1,233 | 32,025 | — | 52,787 | |||||||||||||||||||||
Gross operating margin by individual business segment and in total: | ||||||||||||||||||||||||||||
Year ended December 31, 2006 | 103,407 | 333,399 | 752,548 | 173,095 | — | — | 1,362,449 | |||||||||||||||||||||
Year ended December 31, 2005 | 77,505 | 353,076 | 579,706 | 126,060 | — | — | 1,136,347 | |||||||||||||||||||||
Year ended December 31, 2004 | 36,478 | 90,977 | 374,196 | 121,515 | 32,025 | — | 655,191 | |||||||||||||||||||||
Segment assets: | ||||||||||||||||||||||||||||
At December 31, 2006 | 734,659 | 3,611,974 | 3,249,486 | 502,345 | — | 1,734,083 | 9,832,547 | |||||||||||||||||||||
At December 31, 2005 | 632,222 | 3,622,318 | 3,075,048 | 504,841 | — | 854,595 | 8,689,024 | |||||||||||||||||||||
Investments in and advances to unconsolidated affiliates (see Note 11): | ||||||||||||||||||||||||||||
At December 31, 2006 | 310,136 | 124,591 | 111,229 | 18,603 | — | — | 564,559 | |||||||||||||||||||||
At December 31, 2005 | 316,844 | 4,644 | 130,376 | 20,057 | — | — | 471,921 | |||||||||||||||||||||
Intangible Assets (see Note 13): | ||||||||||||||||||||||||||||
At December 31, 2006 | 152,376 | 386,149 | 417,950 | 47,480 | — | — | 1,003,955 | |||||||||||||||||||||
At December 31, 2005 | 174,532 | 413,843 | 275,778 | 49,473 | — | — | 913,626 | |||||||||||||||||||||
Goodwill (see Note 13): | ||||||||||||||||||||||||||||
At December 31, 2006 | 82,135 | 282,121 | 152,595 | 73,690 | — | — | 590,541 | |||||||||||||||||||||
At December 31, 2005 | 82,386 | 282,997 | 54,960 | 73,690 | — | — | 494,033 |
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Revenues from consolidated operations | ||||||||||||
EPCO and affiliates | $ | 98,671 | $ | 311 | $ | 2,697 | ||||||
Shell | — | — | 542,912 | |||||||||
Unconsolidated affiliates | 304,559 | 354,461 | 258,541 | |||||||||
Total | $ | 403,230 | $ | 354,772 | $ | 804,150 | ||||||
Operating costs and expenses | ||||||||||||
EPCO and affiliates | $ | 311,537 | $ | 293,134 | $ | 203,100 | ||||||
Shell | — | — | 725,420 | |||||||||
Unconsolidated affiliates | 31,606 | 23,563 | 37,587 | |||||||||
Total | $ | 343,143 | $ | 316,697 | $ | 966,107 | ||||||
General and administrative expenses | ||||||||||||
EPCO and affiliates | $ | 41,265 | $ | 40,954 | $ | 29,307 | ||||||
§ | EPCO and its private company subsidiaries; | ||
§ | Enterprise Products GP, our sole general partner; | ||
§ | Enterprise GP Holdings, which owns and controls our general partner; | ||
§ | Duncan Energy Partners, which is a public company subsidiary of ours; | ||
§ | TEPPCO and TEPPCO GP, which are controlled by affiliates of EPCO; and | ||
§ | the Employee Partnerships. |
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§ | Mont Belvieu Caverns, LLC(“Mont Belvieu Caverns”), a recently formed subsidiary, which owns salt dome storage caverns located in Mont Belvieu, Texas that receive, store and deliver NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States; | ||
§ | Acadian Gas, LLC(“Acadian Gas”), which owns an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. A subsidiary of Acadian Gas owns our 49.5% equity interest in Evangeline. See Note 11; |
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§ | Sabine Propylene Pipeline L.P.(“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana; | ||
§ | Enterprise Lou-Tex Propylene Pipeline L.P.(“Lou-Tex Propylene”), which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and | ||
§ | South Texas NGL Pipelines, LLC(“South Texas NGL”), a recently formed subsidiary, which began transporting NGLs from Corpus Christi, Texas to Mont Belvieu, Texas in January 2007. South Texas NGL owns the DEP South Texas NGL Pipeline System. |
§ | We utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses; | ||
§ | We buy natural gas from and sell natural gas to Acadian Gas in connection with its normal business activities; and | ||
§ | We are the sole shipper on the DEP South Texas NGL Pipeline System. |
§ | indemnification for certain environmental liabilities, tax liabilities and right-of-way defects; | ||
§ | reimbursement of certain expenditures for South Texas NGL and Mont Belvieu Caverns; | ||
§ | a right of first refusal to the Operating Partnership on the equity interests in the current and future subsidiaries of Duncan Energy Partners and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business; and |
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§ | a preemptive right with respect to equity securities issued by certain of Duncan Energy Partners’ subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing. |
§ | certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to Duncan Energy Partners on February 5, 2007 are located; | ||
§ | failure to obtain certain consents and permits necessary for Duncan Energy Partners to conduct its business that arise within three years after February 5, 2007; and | ||
§ | certain income tax liabilities related to the operation of the assets contributed to Duncan Energy Partners attributable to periods prior to February 5, 2007. |
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§ | Distributions of Cash Flow-Each quarter, 100% of the cash distributions received by EPE Unit I from Enterprise GP Holdings will be distributed to the Class A limited partner until Duncan Family Interests has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by EPE Unit I will be distributed to the Class B limited partners. The Class A preferred return equals 1.5625% per quarter, or 6.25% per annum, of the Class A limited partner’s capital base. The Class A limited partner’s capital base equals $51 million plus any unpaid Class A preferred return from prior periods, less any distributions made by EPE Unit I of proceeds from the sale of Enterprise GP Holdings units owned by EPE Unit I (as described below). |
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§ | Liquidating Distributions-Upon liquidation of EPE Unit I, units having a fair market value equal to the Class A limited partner capital base will be distributed to Duncan Family Interests, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners. | ||
§ | Sale Proceeds-If EPE Unit I sells any of the 1,821,428 Enterprise GP Holdings units that it owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above. |
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§ | EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our business, properties and assets (in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services. | ||
§ | 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 in respect of the services provided to us by EPCO. | ||
§ | EPCO will allow us to participate as named insureds in its overall insurance program, with the associated premiums and other costs being allocated to us. |
§ | If a business opportunity to acquire “equity securities” (as defined)is presented to the EPCO Group, us and our general partner, Duncan Energy Partners, its general partner, and its operating partnership, or Enterprise GP Holdings and its general partner, then Enterprise GP Holdings will have the first right to pursue such opportunity. The term “equity securities” is defined to include: |
§ | general partner interests (or securities which have characteristics similar to general partner interests) and incentive distribution rights or similar rights in publicly traded partnerships or interests in “persons” that own or control such general partner or similar interests |
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(collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and | |||
§ | incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates. |
Enterprise GP Holdings will be presumed to desire to acquire the equity securities until such time as its general partner advises the EPCO Group, Enterprise Products GP and DEP Holdings that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by the chief executive officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings. If the purchase price is reasonably likely to be less than such threshold amount, the chief executive officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings. | |||
In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, Enterprise Products GP and DEP Holdings, we will have the second right to pursue such acquisition either for us or, if desired by us in our sole discretion, for the benefit of Duncan Energy Partners. In the event that we affirmatively direct the opportunity to Duncan Energy Partners, Duncan Energy Partners may pursue such acquisition. We will be presumed to desire to acquire the equity securities until such time as Enterprise Products GP advises the EPCO Group and DEP Holdings that we have abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, we will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing Enterprise Products GP��s chief executive officer and ACG Committee. In the event we abandon the acquisition opportunity for the equity securities and so notify the EPCO Group and DEP Holdings, the EPCO Group may pursue the acquisition or offer the opportunity to EPCO Holdings or TEPPCO, TEPPCO GP and their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates. | |||
§ | If any business opportunity not covered by the preceding bullet point (i.e. not involving “equity securities”) is presented to the EPCO Group, Enterprise GP Holdings, EPE Holdings, Duncan Energy Partners, DEP Holdings, our general partner or us, we will have the first right to pursue such opportunity either for us or, if desired by us in our sole discretion, for the benefit of Duncan Energy Partners. We will be presumed to desire to pursue the business opportunity until such time as Enterprise Products GP advises the EPCO Group, EPE Holdings and DEP Holdings that we have abandoned the pursuit of such business opportunity. | ||
In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the chief executive officer of Enterprise Products GP after consultation with and subject to the approval of the ACG Committee of Enterprise Products GP. If the purchase price or cost is reasonably likely to be less than such threshold amount, the chief executive officer of Enterprise Products GP may make the determination to decline the business opportunity without consulting Enterprise Products GP’s ACG Committee. In the event that we affirmatively direct the business opportunity to Duncan Energy Partners, Duncan Energy Partners may pursue such business opportunity. In the event that we abandon the business opportunity for us and for Duncan Energy Partners and so notify the EPCO Group, EPE Holdings and DEP Holdings, Enterprise GP Holdings will have the second right to pursue such business opportunity, and will be presumed to desire to do so, until such time as EPE Holdings shall have determined to abandon the pursuit of |
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§ | We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility. Revenues from Evangeline were $277.7 million, $318.8 million and $233.9 million for the years ended December 31, 2006, 2005 and 2004. In addition, we furnished $1.1 million in letters of credit on behalf of Evangeline at December 31, 2006. | ||
§ | We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. Expenses with Promix were $34.9 million, $26.0 million and $23.2 million for the years ended December 31, 2006, 2005 and 2004. Additionally, revenues from Promix were $21.8 million, $25.8 million and $18.6 million for the years ended December 31, 2006, 2005 and 2004. | ||
§ | We perform management services for certain of our unconsolidated affiliates. These fees were $8.9 million, $8.3 million and $2.1 million for the years ended December 31, 2006, 2005 and 2004. |
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§ | the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest; | ||
§ | any customary or accepted industry practices and any customary or historical dealings with a particular person; | ||
§ | any applicable generally accepted accounting practices or principles; and | ||
§ | such additional factors as the committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. |
§ | Review a summary of the proposed transaction(s) that outlines (i) its terms and conditions (explicit and implicit), (ii) a brief history of the transaction, and (iii) the impact that the transaction will have on our unitholders and personnel, including earnings per unit and distributable cash flow. | ||
§ | Review due diligence findings by management and make additional due diligence requests, if necessary. |
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§ | Engage third-party independent advisors, where necessary, to provide committee members with comparable market values, legal advice and similar services directly related to the proposed transaction. | ||
§ | Conduct interviews regarding the proposed transaction with the most knowledgeable company officials to ensure that the committee members have all relevant facts before rendering their judgment. |
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Current: | ||||||||||||
Federal | $ | 7,694 | $ | 1,105 | $ | — | ||||||
State | 1,148 | 301 | 157 | |||||||||
Total current | 8,842 | 1,406 | 157 | |||||||||
Deferred: | ||||||||||||
Federal | 6,109 | 5,968 | 1,620 | |||||||||
State | 6,372 | 988 | 1,984 | |||||||||
Total deferred | 12,481 | 6,956 | 3,604 | |||||||||
Total provision for income taxes | $ | 21,323 | $ | 8,362 | $ | 3,761 | ||||||
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Taxes computed by applying the federal statutory rate | $ | 13,347 | $ | 7,656 | $ | 2,308 | ||||||
State income taxes (net of federal benefit) | 7,723 | 838 | 1,392 | |||||||||
Taxes charged to cumulative effect of changes in accounting principle | (3 | ) | 65 | — | ||||||||
Other permanent differences | 256 | (197 | ) | 61 | ||||||||
Provision for income taxes | $ | 21,323 | $ | 8,362 | $ | 3,761 | ||||||
Effective income tax rate | 56 | % | 38 | % | 57 | % | ||||||
At December 31, | ||||||||
2006 | 2005 | |||||||
Deferred Tax Assets: | ||||||||
Property, plant and equipment — Dixie | $ | — | $ | 855 | ||||
Net operating loss carryforwards | 19,175 | 17,121 | ||||||
Credit carryover | 26 | — | ||||||
Charitable contribution carryover | 12 | — | ||||||
Employee benefit plans | 1,990 | 2,403 | ||||||
Deferred revenue | 328 | 448 | ||||||
Equity investment in partnerships | 223 | — | ||||||
Asset retirement obligation | 43 | — | ||||||
Accruals | 709 | 116 | ||||||
Total Deferred Tax Assets | 22,506 | 20,943 | ||||||
Valuation allowance | (2,994 | ) | (2,870 | ) | ||||
Net Deferred Tax Assets | 19,512 | 18,073 | ||||||
Deferred Tax Liabilities: | ||||||||
Property, plant and equipment | 30,604 | 13,907 | ||||||
Other | 78 | 6 | ||||||
Total Deferred Tax Liabilities | 30,682 | 13,913 | ||||||
Total Net Deferred Tax Assets (Liabilities) | $ | (11,170 | ) | $ | 4,160 | |||
Current portion of total net deferred tax assets | $ | 698 | $ | 554 | ||||
Long-term portion of total net deferred tax assets (liabilities) | $ | (11,868 | ) | $ | 3,606 | |||
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For The Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Net income | $ | 601,155 | $ | 419,508 | $ | 268,261 | ||||||
Less incentive earnings allocations to Enterprise Products GP | (86,710 | ) | (63,884 | ) | (32,391 | ) | ||||||
Net income available after incentive earnings allocation | 514,445 | 355,624 | 235,870 | |||||||||
Multiplied by Enterprise Products GP ownership interest | 2.0 | % | 2.0 | % | 2.0 | % | ||||||
Standard earnings allocation to Enterprise Products GP | $ | 10,289 | $ | 7,112 | $ | 4,717 | ||||||
Incentive earnings allocation to Enterprise Products GP | $ | 86,710 | $ | 63,884 | $ | 32,391 | ||||||
Standard earnings allocation to Enterprise Products GP | 10,289 | 7,112 | 4,717 | |||||||||
Enterprise Products GP interest in net income | $ | 96,999 | $ | 70,996 | $ | 37,108 | ||||||
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For The Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Income before changes in accounting principles and Enterprise Products GP interest | $ | 599,683 | $ | 423,716 | $ | 257,480 | ||||||
Cumulative effect of changes in accounting principles | 1,472 | (4,208 | ) | 10,781 | ||||||||
Net income | 601,155 | 419,508 | 268,261 | |||||||||
Less Enterprise Products GP interest in net income | (96,999 | ) | (70,996 | ) | (37,108 | ) | ||||||
Net income available to limited partners | $ | 504,156 | $ | 348,512 | $ | 231,153 | ||||||
BASIC EARNINGS PER UNIT | ||||||||||||
Numerator | ||||||||||||
Income before changes in accounting principles and Enterprise Products GP interest | $ | 599,683 | $ | 423,716 | $ | 257,480 | ||||||
Cumulative effect of changes in accounting principles | 1,472 | (4,208 | ) | 10,781 | ||||||||
Enterprise Products GP interest in net income | (96,999 | ) | (70,996 | ) | (37,108 | ) | ||||||
Limited partners’ interest in net income | $ | 504,156 | $ | 348,512 | $ | 231,153 | ||||||
Denominator | ||||||||||||
Common units | 413,472 | 381,857 | 262,838 | |||||||||
Restricted units | 970 | 606 | 141 | |||||||||
Class B special units | — | — | 2,532 | |||||||||
Total | 414,442 | 382,463 | 265,511 | |||||||||
Basic earnings per unit | ||||||||||||
Income per unit before changes in accounting principles and Enterprise Products GP interest | $ | 1.45 | $ | 1.11 | $ | 0.97 | ||||||
Cumulative effect of changes in accounting principles | — | (0.01 | ) | 0.04 | ||||||||
Less Enterprise Products GP interest in net income | (0.23 | ) | (0.19 | ) | (0.14 | ) | ||||||
Limited partners’ interest in net income | $ | 1.22 | $ | 0.91 | $ | 0.87 | ||||||
DILUTED EARNINGS PER UNIT | ||||||||||||
Numerator | ||||||||||||
Income before changes in accounting principles and Enterprise Products GP interest | $ | 599,683 | $ | 423,716 | $ | 257,480 | ||||||
Cumulative effect of changes in accounting principles | 1,472 | (4,208 | ) | 10,781 | ||||||||
Less Enterprise Products GP interest in net income | (96,999 | ) | (70,996 | ) | (37,108 | ) | ||||||
Limited partners’ interest in net income | $ | 504,156 | $ | 348,512 | $ | 231,153 | ||||||
Denominator | ||||||||||||
Common units | 413,472 | 381,857 | 262,838 | |||||||||
Class B special units | — | — | 2,532 | |||||||||
Time-vested restricted units | 970 | 606 | 141 | |||||||||
Performance-based restricted units | 20 | 45 | 14 | |||||||||
Series F2 convertible units | — | — | 22 | |||||||||
Incremental option units | 297 | 455 | 498 | |||||||||
Total | 414,759 | 382,963 | 266,045 | |||||||||
Diluted earnings per unit | ||||||||||||
Income per unit before changes in accounting principles and Enterprise Products GP interest | $ | 1.45 | $ | 1.11 | $ | 0.97 | ||||||
Cumulative effect of changes in accounting principles | — | (0.01 | ) | 0.04 | ||||||||
Enterprise Products GP interest in net income | (0.23 | ) | (0.19 | ) | (0.14 | ) | ||||||
Limited partners’ interest in net income | $ | 1.22 | $ | 0.91 | $ | 0.87 | ||||||
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Payment or Settlement due by Period | ||||||||||||||||||||||||||||
Contractual Obligations | Total | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | |||||||||||||||||||||
Scheduled maturities of long-term debt | $ | 5,329,068 | $ | — | $ | — | $ | 500,000 | $ | 569,068 | $ | 1,360,000 | $ | 2,900,000 | ||||||||||||||
Operating lease obligations | $ | 274,700 | $ | 19,190 | $ | 19,877 | $ | 16,374 | $ | 15,688 | $ | 16,263 | $ | 187,308 | ||||||||||||||
Purchase obligations: | ||||||||||||||||||||||||||||
Product purchase commitments: | ||||||||||||||||||||||||||||
Estimated payment obligations: | ||||||||||||||||||||||||||||
Natural gas | $ | 920,736 | $ | 153,316 | $ | 153,736 | $ | 153,316 | $ | 153,316 | $ | 153,316 | $ | 153,736 | ||||||||||||||
NGLs | $ | 2,902,805 | $ | 959,127 | $ | 223,570 | $ | 213,315 | $ | 213,315 | $ | 213,315 | $ | 1,080,163 | ||||||||||||||
Petrochemicals | $ | 2,656,633 | $ | 1,110,957 | $ | 448,334 | $ | 245,028 | $ | 220,037 | $ | 119,397 | $ | 512,880 | ||||||||||||||
Other | $ | 79,418 | $ | 35,183 | $ | 27,653 | $ | 13,681 | $ | 765 | $ | 659 | $ | 1,477 | ||||||||||||||
Underlying major volume commitments: | ||||||||||||||||||||||||||||
Natural gas (in BBtus) | 109,600 | 18,250 | 18,300 | 18,250 | 18,250 | 18,250 | 18,300 | |||||||||||||||||||||
NGLs (in MBbls) | 68,331 | 21,957 | 5,322 | 5,086 | 5,086 | 5,086 | 25,794 | |||||||||||||||||||||
Petrochemicals (in MBbls) | 45,535 | 19,250 | 7,460 | 4,289 | 3,670 | 2,024 | 8,842 | |||||||||||||||||||||
Service payment commitments | $ | 15,725 | $ | 10,413 | $ | 3,759 | $ | 900 | $ | 93 | $ | 93 | $ | 467 | ||||||||||||||
Capital expenditure commitments | $ | 239,000 | $ | 239,000 | $ | — | $ | — | $ | — | $ | — | $ | — |
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§ | We have long and short-term product purchase obligations for NGLs, certain petrochemicals and natural gas 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 indicated. Our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2006 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. At December 31, 2006, we do not have any 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 third-party providers for services such as equipment maintenance agreements. Our contractual payment obligations vary by contract. The preceding table shows our future payment obligations under these service contracts. | ||
§ | We have short-term payment obligations relating to our capital projects and those of our unconsolidated affiliates. These commitments represent unconditional payment obligations to vendors for services rendered or products purchased. The preceding table presents our share of such commitments for the periods indicated. |
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Business interruption proceeds: | ||||
Hurricane Ivan | $ | 17,382 | ||
Hurricane Katrina | 24,500 | |||
Hurricane Rita | 22,000 | |||
Total proceeds | $ | 63,882 | ||
Property damage proceeds: | ||||
Hurricane Ivan | $ | 24,104 | ||
Hurricane Katrina | 7,500 | |||
Hurricane Rita | 3,000 | |||
Total proceeds | $ | 34,604 | ||
Total proceeds received during 2006 | $ | 98,486 | ||
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Decrease (increase) in: | ||||||||||||
Accounts and notes receivable | $ | 155,628 | $ | (363,857 | ) | $ | (453,904 | ) | ||||
Inventories | (66,288 | ) | (148,846 | ) | (44,202 | ) | ||||||
Prepaid and other current assets | 14,261 | (51,163 | ) | 2,726 | ||||||||
Other assets | (22,581 | ) | 58,762 | (6,073 | ) | |||||||
Increase (decrease) in: | ||||||||||||
Accounts payable | (12,278 | ) | 45,802 | 110,497 | ||||||||
Accrued gas payable | (8,344 | ) | 349,979 | 286,089 | ||||||||
Accrued expenses | (62,963 | ) | (161,989 | ) | 8,800 | |||||||
Accrued interest | 19,671 | 858 | (199 | ) | ||||||||
Other current liabilities | 74,206 | 2,274 | 6,534 | |||||||||
Other liabilities | (7,894 | ) | 1,785 | (3,993 | ) | |||||||
Net effect of changes in operating accounts | $ | 83,418 | $ | (266,395 | ) | $ | (93,725 | ) | ||||
Cash payments for interest, net of $55,660, $22,046 and $2,766 capitalized in 2006, 2005 and 2004, respectively | $ | 213,365 | $ | 239,088 | $ | 135,797 | ||||||
Cash payments for federal and state income taxes | $ | 10,497 | $ | 5,160 | $ | 182 | ||||||
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Assets acquired | $ | 477,015 | $ | 353,176 | $ | 5,946,294 | ||||||
Less liabilities assumed | (19,403 | ) | (23,940 | ) | (2,269,893 | ) | ||||||
Net assets acquired | 457,612 | 329,236 | 3,676,401 | |||||||||
Less equity issued | (181,112 | ) | — | (2,910,772 | ) | |||||||
Less cash acquired | — | (2,634 | ) | (40,968 | ) | |||||||
Cash used for business combinations, net of cash received | $ | 276,500 | $ | 326,602 | $ | 724,661 | ||||||
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First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
For the Year Ended December 31, 2006: | ||||||||||||||||
Revenues | $ | 3,250,074 | $ | 3,517,853 | $ | 3,872,525 | $ | 3,350,517 | ||||||||
Operating income | 193,500 | 186,045 | 274,184 | 206,323 | ||||||||||||
Income before changes in accounting principles | 132,302 | 126,295 | 208,302 | 132,784 | ||||||||||||
Net income | 133,777 | 126,295 | 208,302 | 132,781 | ||||||||||||
Income per unit before changes in accounting principles: | ||||||||||||||||
Basic | $ | 0.28 | $ | 0.26 | $ | 0.43 | $ | 0.25 | ||||||||
Diluted | $ | 0.28 | $ | 0.26 | $ | 0.43 | $ | 0.25 | ||||||||
Net income per unit: | ||||||||||||||||
Basic | $ | 0.28 | $ | 0.26 | $ | 0.43 | $ | 0.25 | ||||||||
Diluted | $ | 0.28 | $ | 0.26 | $ | 0.43 | $ | 0.25 | ||||||||
For the Year Ended December 31, 2005: | ||||||||||||||||
Revenues | $ | 2,555,522 | $ | 2,671,768 | $ | 3,249,291 | $ | 3,780,378 | ||||||||
Operating income | 165,464 | 125,506 | 194,397 | 177,649 | ||||||||||||
Income before changes in accounting principles | 109,256 | 70,659 | 131,169 | 112,632 | ||||||||||||
Net income | 109,256 | 70,659 | 131,169 | 108,424 | ||||||||||||
Income per unit before changes in accounting principles: | ||||||||||||||||
Basic | $ | 0.25 | $ | 0.14 | $ | 0.29 | $ | 0.24 | ||||||||
Diluted | $ | 0.25 | $ | 0.14 | $ | 0.29 | $ | 0.24 | ||||||||
Net income per unit: | ||||||||||||||||
Basic | $ | 0.25 | $ | 0.14 | $ | 0.29 | $ | 0.23 | ||||||||
Diluted | $ | 0.25 | $ | 0.14 | $ | 0.29 | $ | 0.23 |
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At December 31, | ||||||||
2006 | 2005 | |||||||
ASSETS | ||||||||
Current assets | $ | 1,915,937 | $ | 1,960,015 | ||||
Property, plant and equipment, net | 9,832,547 | 8,689,024 | ||||||
Investments in and advances to unconsolidated affiliates | 564,559 | 471,921 | ||||||
Intangible assets, net | 1,003,955 | 913,626 | ||||||
Goodwill | 590,541 | 494,033 | ||||||
Deferred tax asset | 1,632 | 3,606 | ||||||
Other assets | 74,103 | 39,014 | ||||||
Total | $ | 13,983,274 | $ | 12,571,239 | ||||
LIABILITIES AND PARTNERS’ EQUITY | ||||||||
Current liabilities | $ | 1,986,444 | $ | 1,894,227 | ||||
Long-term debt | 5,295,590 | 4,833,781 | ||||||
Other long-term liabilities | 99,845 | 84,486 | ||||||
Minority interest | 136,249 | 106,159 | ||||||
Partners’ equity | 6,465,146 | 5,652,586 | ||||||
Total | $ | 13,983,274 | $ | 12,571,239 | ||||
Total principal amount of Operating Partnership debt obligations guaranteed by us | $ | 5,314,000 | $ | 4,844,000 | ||||
For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Revenues | $ | 13,990,969 | $ | 12,256,959 | $ | 8,321,202 | ||||||
Costs and expenses | 13,148,530 | 11,605,923 | 7,946,816 | |||||||||
Equity in income of unconsolidated affiliates | 21,565 | 14,548 | 52,787 | |||||||||
Operating income | 864,004 | 665,584 | 427,173 | |||||||||
Other expense, net | (231,876 | ) | (226,075 | ) | (153,251 | ) | ||||||
Income before provision for income taxes, minority interest and changes in accounting principles | 632,128 | 439,509 | 273,922 | |||||||||
Provision for income taxes | (21,198 | ) | (8,362 | ) | (3,761 | ) | ||||||
Income before minority interest and changes in accounting principles | 610,930 | 431,147 | 270,161 | |||||||||
Minority interest | (9,190 | ) | (5,989 | ) | (8,072 | ) | ||||||
Income before changes in accounting principles | 601,740 | 425,158 | 262,089 | |||||||||
Cumulative effect of changes in accounting principles | 1,472 | (4,208 | ) | 10,781 | ||||||||
Net income | $ | 603,212 | $ | 420,950 | $ | 272,870 | ||||||
F-87
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VALUATION AND QUALIFYING ACCOUNTS
(Dollars in thousands)
Additions | ||||||||||||||||||||
Balance At | Charged To | Charged To | ||||||||||||||||||
Beginning | Costs And | Other | Balance At | |||||||||||||||||
Description | Of Period | Expenses | Accounts | Deductions | End of Period | |||||||||||||||
Accounts receivable — trade | ||||||||||||||||||||
Allowance for doubtful accounts(1) | ||||||||||||||||||||
2006 | $ | 37,329 | $ | 473 | $ | — | $ | (14,396 | ) | $ | 23,406 | |||||||||
2005 | 32,773 | 5,391 | 5,541 | (6,376 | ) | 37,329 | ||||||||||||||
2004 | 20,423 | 4,840 | 12,621 | (5,111 | ) | 32,773 |
(1) | For additional information regarding our allowance for doubtful accounts, see Note 2. |
F-88
Table of Contents
Exhibit | ||
Number | Description of Exhibit | |
4.47 | Third Amendment dated January 5, 2007, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004 among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents and Mizuho Corporate Bank, LTD, SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents. | |
10.8 | Amendment No. 1 to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007. | |
10.13 | EPE Unit II, L.P. Agreement of Limited Partnership. | |
12.1 | Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2006, 2005, 2004, 2003 and 2002. | |
21.1 | List of subsidiaries as of February 28, 2007. | |
23.1 | Consent of Deloitte & Touche LLP. | |
31.1 | Sarbanes-Oxley Section 302 certification of Robert G. Phillips for Enterprise Products Partners L.P. for the December 31, 2006 annual report on Form 10-K. | |
31.2 | Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the December 31, 2006 annual report on Form 10-K. | |
32.1 | Section 1350 certification of Robert G. Phillips for the December 31, 2006 annual report on Form 10-K. | |
32.2 | Section 1350 certification of Michael A. Creel for the December 31, 2006 annual report on Form 10-K. |