Table of Contents
SECURITIES AND EXCHANGE COMMISSION
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended December 31, 2007 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to . Commission file number: 1-14323 |
Delaware | 76-0568219 | |
(State or Other Jurisdiction of | (I.R.S. Employer Identification No.) | |
Incorporation or Organization) | ||
1100 Louisiana, 10thFloor, Houston, Texas (Address of Principal Executive Offices) | 77002 (Zip Code) |
(Registrant’s Telephone Number, Including Area Code)
Title of Each Class | Name of Each Exchange On Which Registered | |
Common Units | New York Stock Exchange |
Large accelerated filerþ | Accelerated filero | |||||
Non-accelerated filer o | (Do not check if a smaller reporting company) | Smaller Reporting Companyo |
TABLE OF CONTENTS
Table of Contents
ANNUAL REPORT
1
Table of Contents
§ | capitalize on expected increases in natural gas, NGL and crude oil production resulting from development activities in the Rocky Mountains and U.S. Gulf Coast regions, including the Gulf of Mexico; | ||
§ | capitalize on expected demand growth for natural gas, NGLs, crude oil and refined products; | ||
§ | maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary midstream energy assets; | ||
§ | 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. |
2
Table of Contents
§ | NGL Pipelines & Services; | ||
§ | Onshore Natural Gas Pipelines & Services; | ||
§ | Offshore Pipelines & Services; and | ||
§ | Petrochemical Services. |
3
Table of Contents
/d BBtus Bcf MBPD MMBbls MMBtus MMcf | = per day = billion British thermal units = billion cubic feet = thousand barrels per day = million barrels = million British thermal units = million cubic feet |
4
Table of Contents
5
Table of Contents
6
Table of Contents
7
Table of Contents
Net Gas | Total Gas | |||||||||||
Our | Processing | Processing | ||||||||||
Ownership | Capacity | Capacity | ||||||||||
Description of Asset | Location(s) | Interest | (Bcf/d)(1) | (Bcf/d) | ||||||||
Natural gas processing facilities: | ||||||||||||
Pioneer (2) | Wyoming | 100% | 1.35 | 1.35 | ||||||||
Meeker (3) | Colorado | 100% | 0.75 | 0.75 | ||||||||
Toca | Louisiana | 63.9% | 0.70 | 1.10 | ||||||||
Chaco | New Mexico | 100% | 0.65 | 0.65 | ||||||||
North Terrebonne | Louisiana | 48.8% | 0.63 | 1.30 | ||||||||
Calumet | Louisiana | 32.0% | 0.51 | 1.60 | ||||||||
Neptune | Louisiana | 66% | 0.43 | 0.65 | ||||||||
Pascagoula | Mississippi | 40% | 0.40 | 1.50 | ||||||||
Yscloskey | Louisiana | 18.3% | 0.34 | 1.85 | ||||||||
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 (11 facilities) (4) | Texas, New Mexico, Louisiana | Various (5) | 1.27 | 3.44 | ||||||||
Total processing capacities | 8.38 | 15.54 | ||||||||||
(1) | The approximate net natural gas processing 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 a silica gel natural gas processing facility from TEPPCO in March 2006 and subsequently increased the processing capacity from 0.3 Bcf/d to 0.6 Bcf/d. In addition, we constructed a new cryogenic processing facility having 0.75 Bcf/d of processing capacity, which became operational in February 2008. | |
(3) | In October 2007, we commenced natural gas processing operations at our Meeker facility. Phase II of the Meeker facility, which is under construction and expected to be completed in the third quarter of 2008, will double the natural gas processing capacity to 1.5 Bcf/d at this facility. | |
(4) | 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, Shilling 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 Venice Energy Services Company, L.L.C. (“VESCO”). | |
(5) | Our ownership in these facilities ranges from 7.4% to 100%. |
8
Table of Contents
Useable | ||||||||||||
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% | 7,808 | |||||||||
Dixie Pipeline | South and Southeastern U.S. | 74.2% (1) | 1,371 | |||||||||
Seminole Pipeline | Texas | 90% (2) | 1,342 | |||||||||
EPD South Texas NGL System | Texas | 100% | 1,039 | |||||||||
Louisiana Pipeline System | Louisiana | Various (3) | 612 | |||||||||
Promix NGL Gathering System | Louisiana | 50% | 364 | |||||||||
DEP South Texas NGL Pipeline System | Texas | 100% (4) | 286 | |||||||||
Houston Ship Channel | Texas | 100% | 266 | |||||||||
Lou-Tex NGL | Texas, Louisiana | 100% | 205 | |||||||||
Others (5 systems) (5) | Various | Various | 465 | |||||||||
Total miles | 13,758 | |||||||||||
NGL and related product storage facilities by state: | ||||||||||||
Texas (6) | 124.5 | |||||||||||
Louisiana | 15.3 | |||||||||||
Mississippi | 5.7 | |||||||||||
Others (Arizona, Georgia, Iowa, Kansas, Nebraska, Oklahoma) | 9.4 | |||||||||||
Total capacity (7) | 154.9 | |||||||||||
(1) | We hold a 74.2% interest in this system through a majority owned subsidiary, Dixie Pipeline Company (“Dixie”). | |
(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 EPO (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 our Meeker pipeline in Colorado. We completed the Meeker pipeline in 2007, which transports NGLs from our Meeker natural gas processing facility to the Mid-America Pipeline System. | |
(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 154.9 MMBbls of total useable storage capacity includes 20.8 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 2,785-mile Rocky Mountain pipeline, the 2,771-mile Conway North pipeline and the 2,252-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. During 2007, the Rocky Mountain pipeline’s capacity was increased by 50 MBPD. 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 |
9
Table of Contents
Conway North segment has access to NGL supplies from Canada’s Western Sedimentary Basin through third-party connections. The Conway South pipeline, which completed an expansion in 2007, connects the Conway hub with Kansas refineries and transports NGLs to and from Conway, Kansas to the Hobbs hub. The Mid-America Pipeline System interconnects with our Seminole Pipeline and Hobbs NGL fractionator and storage facility at the Hobbs hub. We also own fifteen unregulated propane terminals that are an integral part of the Mid-America Pipeline System. | |||
During 2007, approximately 51% 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, the Piceance Basin of Colorado, the Uintah Basin of Colorado and Utah 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 contributed a direct 66% equity interest in South Texas NGL Pipelines, LLC (“South Texas NGL”), our subsidiary that owns the DEP South Texas NGL Pipeline System, to Duncan Energy Partners effective February 1, 2007. We own the remaining 34% direct equity interest in South Texas NGL. For additional information regarding Duncan Energy Partners, see “Other Items – Initial Public Offering of Duncan Energy Partners” included under Item 7 of this annual report. | |||
§ | 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. |
10
Table of Contents
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. | |||
§ | 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. |
Net | Total | |||||||||||
Our | Plant | Plant | ||||||||||
Ownership | Capacity | Capacity | ||||||||||
Description of Asset | Location(s) | Interest | (MBPD) (1) | (MBPD) | ||||||||
NGL fractionation facilities: | ||||||||||||
Mont Belvieu | Texas | 75% | 178 | 230 | ||||||||
Shoup and Armstrong | Texas | 100% | 87 | 87 | ||||||||
Hobbs | Texas | 100% | 75 | 75 | ||||||||
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 | 519 | 702 | ||||||||||
(1) | The approximate net 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. |
§ | 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. | ||
§ | 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. |
11
Table of Contents
§ | TheHobbsNGL fractionation facility is located in Gaines County, Texas, where it serves petrochemical end users and refineries in West Texas, New Mexico and California. In addition, the Hobbs facility can supply exports to northern Mexico through existing pipeline infrastructure. The Hobbs facility receives mixed NGLs from several major supply basins including Mid-Continent, Permian Basin, San Juan Basin and the Rocky Mountain Overthrust. The facility is strategically located at the interconnect of our Mid-America Pipeline System and Seminole Pipeline, providing us flexibility to supply the nation’s largest NGL hub at Mont Belvieu, Texas as well as access to the second-largest NGL hub at Conway, Kansas. | ||
§ | 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, Venice 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 364-mile Promix NGL Gathering System, Promix owns five NGL storage caverns and a barge loading facility that is integral to its operations. | ||
§ | TheBRFfacility fractionates mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana. |
12
Table of Contents
13
Table of Contents
Approx. Net | ||||||||||||||||
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% (1) | 6,976 | 5,155 | ||||||||||||
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 | 1,149 | ||||||||||||
Jonah Gathering System | Wyoming | 19.4% | 643 | 387 | ||||||||||||
Waha Gathering System | Texas, New Mexico | 100% | 465 | 380 | ||||||||||||
Carlsbad Gathering System | Texas, New Mexico | 100% | 919 | 220 | ||||||||||||
Alabama Intrastate System | Alabama | 100% | 408 | 200 | ||||||||||||
Encinal Gathering System | Texas | 100% | 449 | 143 | ||||||||||||
Other (6 systems) (3) | Texas, Mississippi | Various (4) | 743 | |||||||||||||
Total miles | 17,758 | |||||||||||||||
Natural gas storage facilities: | ||||||||||||||||
Petal | Mississippi | 100% | 14.1 | |||||||||||||
Hattiesburg | Mississippi | 100% | 4.0 | |||||||||||||
Wilson | Texas | Leased (5) | 6.4 | |||||||||||||
Acadian | Louisiana | Leased (6) | 3.0 | |||||||||||||
Total gross capacity | 27.5 | |||||||||||||||
(1) | We own a 50% undivided interest in the 641-mile Channel pipeline system, which is a component of the Texas Intrastate System. The remaining 50% is owned by affiliates of Energy Transfer Equity. In addition, we own less than a 100% undivided interest in certain segments of the Enterprise Texas pipeline system. | |
(2) | Reflects consolidated ownership of Acadian Gas by EPO (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 and Hattiesburg pipelines 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 Canales gathering system in connection with the Encinal acquisition in July 2006. The Petal and Hattiesburg pipelines are integral components of our natural gas storage operations. | |
(4) | We own 100% of these assets with the exception of the Indian Springs system, in which we own an 80% undivided 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. |
14
Table of Contents
§ | 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 as well as to connections with intrastate and interstate pipelines. 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 6,106-mile Enterprise Texas pipeline system, the 229-mile TPC Offshore gathering system and the 641-mile Channel pipeline system. The leased Wilson natural gas storage facility is an integral part of the Texas Intrastate System. | ||
In November 2006, we announced an expansion of our Texas Intrastate System with the construction of the Sherman Extension that will transport up to 1.1 Bcf/d of natural gas from the growing Barnett Shale area of North Texas. For information regarding this expansion projects, see “Liquidity and Capital Resources — Capital Spending” included under Item 7 of this annual report. | |||
§ | ThePiceance Creek Gathering Systemconsists of a recently constructed natural gas gathering pipeline located in the Piceance Basin of northwestern Colorado. We acquired this pipeline 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 1.5 Bcf/d Meeker natural gas treating and processing complex, which completed its first phase of construction in October 2007. We placed the Piceance Creek Gathering System into service in January 2007 and it currently transports approximately 520 MMcf/d of natural gas. With connectivity to EnCana’s Great Divide Gathering System, our Piceance Creek Gathering System has access to natural gas production from the southern portion of the Piceance basin, including production from EnCana’s Mamm Creek field. | ||
§ | 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 10,630 producing wells in the San Juan Basin and delivers the natural gas to natural gas processing facilities, including our Chaco facility. | ||
In November 2007, we and the Jicarilla Apache Nation announced the formation of a joint venture to own and operate natural gas gathering assets located on or near Jicarilla Apache Nation reservation lands. For additional information regarding this new joint venture, see “Recent Developments” included under Item 7 of this annual report. | |||
§ | 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, LLC (“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 equity interest in Acadian Gas. For additional information regarding Duncan Energy Partners, see “Other Items — Initial Public Offering of Duncan Energy Partners” included under Item 7 of this annual report. Acadian Gas owns a 49.5% indirect interest in the Evangeline pipeline. | |||
§ | 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 |
15
Table of Contents
§ | TheWaha and Carlsbad Gathering Systems(formerly our Permian Basin System) gather natural gas from wells in the Permian Basin region of Texas and New Mexico and deliver natural gas into the El Paso Natural Gas, Transwestern and Oasis pipelines. | ||
§ | 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 in south Texas 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. |
16
Table of Contents
17
Table of Contents
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: | |||||||||||||||||||||
High Island Offshore System | 100% | 291 | 1,800 | ||||||||||||||||||
Viosca Knoll Gathering System | 100% | 172 | 1,000 | ||||||||||||||||||
Independence Trail (1) | 100% | 134 | 1,000 | ||||||||||||||||||
Green Canyon Laterals | Various (2) | 95 | 599 | ||||||||||||||||||
Anaconda Gathering System (3) | 100% | 137 | 550 | ||||||||||||||||||
Phoenix Gathering System | 100% | 77 | 450 | ||||||||||||||||||
Falcon Natural Gas Pipeline | 100% | 14 | 400 | ||||||||||||||||||
Manta Ray Offshore Gathering System | 25.7% | 250 | 206 | ||||||||||||||||||
Nautilus System | 25.7% | 101 | 154 | ||||||||||||||||||
VESCO Gathering System | 13.1% | 260 | 105 | ||||||||||||||||||
Nemo Gathering System | 33.9% | 24 | 102 | ||||||||||||||||||
Total miles | 1,555 | ||||||||||||||||||||
Offshore crude oil pipelines: | |||||||||||||||||||||
Cameron Highway Oil Pipeline | 50% | 374 | 250 | ||||||||||||||||||
Poseidon Oil Pipeline System | 36% | 372 | 144 | ||||||||||||||||||
Allegheny Oil Pipeline | 100% | 43 | 140 | ||||||||||||||||||
Marco Polo Oil Pipeline | 100% | 37 | 120 | ||||||||||||||||||
Constitution Oil Pipeline | 100% | 67 | 80 | ||||||||||||||||||
Typhoon Oil Pipeline | 100% | 17 | 80 | ||||||||||||||||||
Tarantula Oil Pipeline | 100% | 4 | 30 | ||||||||||||||||||
Total miles | 914 | ||||||||||||||||||||
Offshore platforms: | |||||||||||||||||||||
Independence Hub (1) | 80% | 8,000 | 800 | NA | |||||||||||||||||
Marco Polo | 50% | 4,300 | 150 | 60 | |||||||||||||||||
Viosca Knoll 817 | 100% | 671 | 145 | 5 | |||||||||||||||||
Garden Banks 72 | 50% | 518 | 40 | 18 | |||||||||||||||||
East Cameron 373 | 100% | 441 | 195 | 3 | |||||||||||||||||
Falcon Nest | 100% | 389 | 400 | 3 |
(1) | In July 2007, the Independence Hub platform and Independence Trail pipeline received first production from deepwater production wells connected to the Independence Hub platform. The Independence Hub platform began earning demand revenues in March 2007. | |
(2) | Our ownership interests in the Green Canyon Laterals ranges from 0% to 100%. | |
(3) | Data shown for the Anaconda Gathering System includes the 30-mile Constitution natural gas pipeline, which we constructed and placed into service in 2006. The Constitution natural gas pipeline has a net capacity of approximately 200 MMcf/d. |
§ | 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 eight pipeline junction and service platforms. This system also includes the 86-mile East Breaks System that connects the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25 to the HIOS pipeline system. |
18
Table of Contents
§ | 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. | ||
§ | TheIndependence Trailnatural gas pipeline transports natural gas from our Independence Hub platform to the Tennessee Gas Pipeline. Natural gas transported on the Independence Trail comes 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. In July 2007, the Independence Trail pipeline received first production from deepwater wells connected to the Independence Hub platform. | ||
§ | TheGreen Canyon Lateralsconsist of 20 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 serves the Constitution and Ticonderoga fields located in the central Gulf of Mexico. | ||
§ | ThePhoenix Gathering Systemconnects the Red Hawk platform located in the Garden Banks area of the Gulf of Mexico to the ANR pipeline system. | ||
§ | 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. | ||
§ | 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. (“Neptune”). | ||
§ | 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. | ||
§ | 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. | ||
§ | 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. |
19
Table of Contents
§ | TheCameron Highway Oil Pipelinegathers 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. | ||
§ | 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. | ||
§ | TheConstitution Oil Pipelineserves the Constitution and Ticonderoga fields located in the central Gulf of Mexico. The Constitution Oil Pipeline connects with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at a pipeline junction platform. |
§ | TheIndependence Hubplatform is located in Mississippi Canyon Block 920. This platform processes natural gas gathered from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. We successfully installed the Independence Hub platform and began earning demand revenues in March 2007. In July 2007, the Independence Hub platform received first production from deepwater wells connected to the platform. Currently, the platform is receiving approximately 900 MMcf/d of natural gas from fifteen wells. | ||
§ | TheMarco Poloplatform, which is located in Green Canyon Block 608, processes crude oil and natural gas from the Marco Polo, K2, K2 North and Genghis Khan fields. These fields are located |
20
Table of Contents
§ | 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, which is located in the Mustang Island Block 103 area of the Gulf of Mexico, currently processes natural gas from the Falcon field. |
21
Table of Contents
22
Table of Contents
Net | Total | |||||||||||||||
Our | Plant | Plant | ||||||||||||||
Ownership | Capacity | Capacity | Length | |||||||||||||
Description of Asset | Location(s) | Interest | (MBPD) | (MBPD) | (Miles) | |||||||||||
Propylene fractionation facilities: | ||||||||||||||||
Mont Belvieu (4 plants) | Texas | Various (1) | 73 | 87 | ||||||||||||
BRPC | Louisiana | 30% (2) | 7 | 23 | ||||||||||||
Total capacity | 80 | 110 | ||||||||||||||
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% | 105 | |||||||||||||
Lake Charles | Texas, Louisiana | 50% | 83 | |||||||||||||
Others (6 systems) (5) | Texas | Various (6) | 211 | |||||||||||||
Total miles | 683 | |||||||||||||||
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 two facilities, which have 14 MBPD and 15 MBPD of plant capacity, respectively. | |
(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 78%, 70% and 70% during 2007, 2006 and 2005, respectively. | |
(4) | Reflects consolidated ownership of these pipelines by EPO (34%) and Duncan Energy Partners (66%). | |
(5) | Includes our Texas City PGP Delivery 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. |
23
Table of Contents
24
Table of Contents
25
Table of Contents
26
Table of Contents
27
Table of Contents
28
Table of Contents
29
Table of Contents
30
Table of Contents
§ | the level of domestic production and consumer product demand; | ||
§ | 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; | ||
§ | the impact of conservation efforts; | ||
§ | the extent of governmental regulation and taxation of production; and | ||
§ | the overall economic environment. |
31
Table of Contents
§ | geographic proximity to the production; | ||
§ | costs of connection; | ||
§ | available capacity; | ||
§ | rates; and | ||
§ | access to markets. |
32
Table of Contents
§ | 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; | ||
§ | 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. |
33
Table of Contents
34
Table of Contents
§ | 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; | ||
§ | 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 |
35
Table of Contents
§ | 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; | ||
§ | 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. |
36
Table of Contents
37
Table of Contents
38
Table of Contents
39
Table of Contents
40
Table of Contents
41
Table of Contents
§ | the ownership interest of a unitholder immediately prior to the issuance will decrease; | ||
§ | the amount of cash available for distributions on each common unit may decrease; | ||
§ | the ratio of taxable income to distributions may increase; | ||
§ | 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 EPGP in its sole discretion. |
42
Table of Contents
§ | neither our partnership agreement nor any other agreement requires EPGP or EPCO to pursue a business strategy that favors us; | ||
§ | decisions of EPGP 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 EPGP; | ||
§ | under our partnership agreement, EPGP determines which costs incurred by it and its affiliates are reimbursable by us; | ||
§ | EPGP is allowed to resolve any conflicts of interest involving us and EPGP and its affiliates; | ||
§ | EPGP 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 EPGP 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 EPGP, including TEPPCO, may compete with us in certain circumstances; | ||
§ | EPGP 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 |
43
Table of Contents
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, EPGP 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 EPGP 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; | ||
§ | EPGP intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us; | ||
§ | EPGP controls the enforcement of obligations owed to us by our general partner and its affiliates; and | ||
§ | EPGP decides whether to retain separate counsel, accountants or others to perform services for us. |
44
Table of Contents
§ | 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. |
45
Table of Contents
46
Table of Contents
47
Table of Contents
48
Table of Contents
Number of | ||||
Votes Cast | ||||
For | 243,283,982 | |||
Against | 13,383,667 | |||
Abstentions | 2,236,957 |
49
Table of Contents
Cash Distribution History | ||||||||||||||||||||
Price Ranges | Per | Record | Payment | |||||||||||||||||
High | Low | Unit | Date | Date | ||||||||||||||||
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 | ||||||||||||
2007 | ||||||||||||||||||||
1st Quarter | $ | 32.750 | $ | 28.060 | $ | 0.4750 | Apr. 30, 2007 | May 10, 2007 | ||||||||||||
2nd Quarter | $ | 33.350 | $ | 30.220 | $ | 0.4825 | Jul. 31, 2007 | Aug. 9, 2007 | ||||||||||||
3rd Quarter | $ | 33.700 | $ | 26.136 | $ | 0.4900 | Oct. 31, 2007 | Nov. 8, 2007 | ||||||||||||
4th Quarter | $ | 32.450 | $ | 29.920 | $ | 0.5000 | Jan. 31, 2008 | Feb. 7, 2008 |
50
Table of Contents
For the Year Ended December 31, | ||||||||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Operating results data:(1) | ||||||||||||||||||||
Revenues | $ | 16,950,125 | $ | 13,990,969 | $ | 12,256,959 | $ | 8,321,202 | $ | 5,346,431 | ||||||||||
Income from continuing operations (2) | $ | 533,674 | $ | 599,683 | $ | 423,716 | $ | 257,480 | $ | 104,546 | ||||||||||
Income per unit from continuing operations: | ||||||||||||||||||||
Basic | $ | 0.96 | $ | 1.22 | $ | 0.92 | $ | 0.83 | $ | 0.42 | ||||||||||
Diluted | $ | 0.96 | $ | 1.22 | $ | 0.92 | $ | 0.83 | $ | 0.41 | ||||||||||
Other financial data: | ||||||||||||||||||||
Distributions per common unit (3) | $ | 1.9475 | $ | 1.825 | $ | 1.698 | $ | 1.540 | $ | 1.470 |
As of December 31, | ||||||||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Financial position data:(1) | ||||||||||||||||||||
Total assets | $ | 16,608,007 | $ | 13,989,718 | $ | 12,591,016 | $ | 11,315,461 | $ | 4,802,814 | ||||||||||
Long-term and current maturities of debt (4) | $ | 6,906,145 | $ | 5,295,590 | $ | 4,833,781 | $ | 4,281,236 | $ | 2,139,548 | ||||||||||
Partners’ equity (5) | $ | 6,131,649 | $ | 6,480,233 | $ | 5,679,309 | $ | 5,328,785 | $ | 1,705,953 | ||||||||||
Total units outstanding (excluding treasury) (5) | 435,297 | 432,408 | 389,861 | 364,786 | 217,780 |
(1) | In general, our historical operating results and financial position have been affected by numerous acquisitions since 2002. 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. | |
(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) | 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. | |
(5) | 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 2003 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. |
51
Table of Contents
§ | Cautionary Note Regarding Forward-Looking Statements. | ||
§ | Significant Relationships Referenced in this Discussion and Analysis. | ||
§ | Overview of Business. | ||
§ | Recent Developments – Discusses significant developments during the year ended December 31, 2007. | ||
§ | Results of Operations – Discusses material year-to-year variances in our Statements of Consolidated Operations. | ||
§ | Liquidity and Capital Resources – Addresses available sources of liquidity and capital resources and includes a discussion of our capital spending program. | ||
§ | Critical Accounting Policies and Estimates. | ||
§ | 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 | |
MMBbls | = million barrels | |
MMBtus | = million British thermal units | |
MMcf | = million cubic feet |
52
Table of Contents
53
Table of Contents
54
Table of Contents
55
Table of Contents
56
Table of Contents
57
Table of Contents
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 | ) | |||||||||||||||||||
2005 Averages | $ | 8.64 | $ | 56.47 | $ | 0.62 | $ | 0.91 | $ | 1.09 | $ | 1.15 | $ | 1.26 | $ | 0.42 | $ | 0.37 | ||||||||||||||||||
2006 Averages | $ | 7.24 | $ | 66.09 | $ | 0.66 | $ | 1.01 | $ | 1.20 | $ | 1.24 | $ | 1.44 | $ | 0.47 | $ | 0.41 | ||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||
1st Quarter | $ | 6.77 | $ | 58.02 | $ | 0.59 | $ | 0.97 | $ | 1.13 | $ | 1.22 | $ | 1.37 | $ | 0.45 | $ | 0.40 | ||||||||||||||||||
2nd Quarter | $ | 7.55 | $ | 64.97 | $ | 0.72 | $ | 1.13 | $ | 1.33 | $ | 1.45 | $ | 1.65 | $ | 0.51 | $ | 0.46 | ||||||||||||||||||
3rd Quarter | $ | 6.16 | $ | 75.48 | $ | 0.82 | $ | 1.23 | $ | 1.44 | $ | 1.49 | $ | 1.68 | $ | 0.52 | $ | 0.46 | ||||||||||||||||||
4th Quarter | $ | 6.97 | $ | 90.75 | $ | 1.04 | $ | 1.51 | $ | 1.79 | $ | 1.80 | $ | 2.01 | $ | 0.59 | $ | 0.54 | ||||||||||||||||||
2007 Averages | $ | 6.86 | $ | 72.30 | $ | 0.79 | $ | 1.21 | $ | 1.42 | $ | 1.49 | $ | 1.68 | $ | 0.52 | $ | 0.47 | ||||||||||||||||||
(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. Polymer-grade propylene represents average CMAI contract pricing. Refinery grade propylene represents an average of CMAI spot prices. | |
(2) | Crude oil price is representative of an index price for West Texas Intermediate. |
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
NGL Pipelines & Services, net: | ||||||||||||
NGL transportation volumes (MBPD) | 1,666 | 1,577 | 1,478 | |||||||||
NGL fractionation volumes (MBPD) | 394 | 312 | 292 | |||||||||
Equity NGL production (MBPD)(1) | 88 | 63 | 68 | |||||||||
Fee-based natural gas processing (MMcf/d) | 2,565 | 2,218 | 1,767 | |||||||||
Onshore Natural Gas Pipelines & Services, net: | ||||||||||||
Natural gas transportation volumes (BBtus/d) | 6,632 | 6,012 | 5,916 | |||||||||
Offshore Pipelines & Services, net: | ||||||||||||
Natural gas transportation volumes (BBtus/d) | 1,641 | 1,520 | 1,780 | |||||||||
Crude oil transportation volumes (MBPD) | 163 | 153 | 127 | |||||||||
Platform gas processing (MMcf/d) | 494 | 159 | 252 | |||||||||
Platform oil processing (MBPD) | 24 | 15 | 7 | |||||||||
Petrochemical Services, net: | ||||||||||||
Butane isomerization volumes (MBPD) | 90 | 81 | 81 | |||||||||
Propylene fractionation volumes (MBPD) | 68 | 56 | 55 | |||||||||
Octane additive production volumes (MBPD) | 9 | 9 | 6 | |||||||||
Petrochemical transportation volumes (MBPD) | 105 | 97 | 64 | |||||||||
Total, net: | ||||||||||||
NGL, crude oil and petrochemical transportation volumes (MBPD) | 1,934 | 1,827 | 1,669 | |||||||||
Natural gas transportation volumes (BBtus/d) | 8,273 | 7,532 | 7,696 | |||||||||
Equivalent transportation volumes (MBPD) (2) | 4,111 | 3,809 | 3,694 | |||||||||
(1) | Volumes for 2005 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. |
58
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Revenues | $ | 16,950,125 | $ | 13,990,969 | $ | 12,256,959 | ||||||
Operating costs and expenses | 16,009,051 | 13,089,091 | 11,546,225 | |||||||||
General and administrative costs | 87,695 | 63,391 | 62,266 | |||||||||
Equity in income of unconsolidated affiliates | 29,658 | 21,565 | 14,548 | |||||||||
Operating income | 883,037 | 860,052 | 663,016 | |||||||||
Interest expense | 311,764 | 238,023 | 230,549 | |||||||||
Provision for income taxes | 15,257 | 21,323 | 8,362 | |||||||||
Minority interest | 30,643 | 9,079 | 5,760 | |||||||||
Net income | 533,674 | 601,155 | 419,508 |
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Gross operating margin by segment: | ||||||||||||
NGL Pipelines & Services | $ | 812,521 | $ | 752,548 | $ | 579,706 | ||||||
Onshore Natural Gas Pipelines & Services | 335,683 | 333,399 | 353,076 | |||||||||
Offshore Pipeline & Services | 171,551 | 103,407 | 77,505 | |||||||||
Petrochemical Services | 172,313 | 173,095 | 126,060 | |||||||||
Total segment gross operating margin | $ | 1,492,068 | $ | 1,362,449 | $ | 1,136,347 | ||||||
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
NGL Pipelines & Services: | ||||||||||||
Sale of NGL products | $ | 11,822,291 | $ | 9,496,926 | $ | 8,176,370 | ||||||
Percent of consolidated revenues | 70 | % | 68 | % | 67 | % | ||||||
Onshore Natural Gas Pipelines & Services: | ||||||||||||
Sale of natural gas | $ | 1,633,214 | $ | 1,228,916 | $ | 1,065,542 | ||||||
Percent of consolidated revenues | 10 | % | 9 | % | 9 | % | ||||||
Petrochemical Services: | ||||||||||||
Sale of petrochemical products | $ | 1,796,251 | $ | 1,545,693 | $ | 1,311,956 | ||||||
Percent of consolidated revenues | 11 | % | 11 | % | 11 | % |
59
Table of Contents
60
Table of Contents
61
Table of Contents
62
Table of Contents
63
Table of Contents
64
Table of Contents
65
Table of Contents
§ | We believe that drilling and production activities in the major producing areas where we operate, including the Gulf of Mexico and supply basins in Texas, San Juan and the Rocky Mountains, could result in increased demand for our midstream energy services. As a result, we expect higher transportation and processing volumes for certain of our existing and newly constructed assets due to increased natural gas, NGL and crude oil production from both onshore and offshore producing areas. | ||
§ | 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 2008 as we supply the Houston, Texas area with natural gas volumes under a long-term agreement with CenterPoint Energy and begin operations on the Sherman Extension pipeline in the Barnett Shale region of North Texas in the fourth quarter of 2008. | ||
§ | We believe that the current strength of the domestic and global economies should 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 due to the higher cost of crude oil derivatives. | ||
§ | Longer term, we believe the expansion of crude oil refineries on the U.S. Gulf Coast could result in opportunities to provide additional midstream services through our existing assets and support the construction of new pipeline and storage facilities. |
66
Table of Contents
67
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Net cash flows provided by operating activities | $ | 1,590,941 | $ | 1,175,069 | $ | 631,708 | ||||||
Cash used in investing activities | 2,533,607 | 1,689,288 | 1,130,395 | |||||||||
Cash provided by financing activities | 979,355 | 494,972 | 516,229 |
68
Table of Contents
§ | Our net cash flows from consolidated businesses (excluding cash payments for interest and taxes and distributions received from unconsolidated affiliates) increased $436.9 million year-to-year. The improvement in cash flow is generally due to increased gross operating margin (see “Results of Operations” within this Item 7) and the timing of related cash collections and disbursements between periods. The $436.9 million year-to-year increase also includes a $42.1 million increase in cash proceeds we received from insurance claims related to certain named storms. See Note 21 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding insurance matters. | ||
§ | Cash distributions received from unconsolidated affiliates increased $30.6 million year-to-year primarily due to improved earnings from our Gulf of Mexico investments, which were negatively impacted during the year ended December 31, 2006 as a result of the lingering effects of Hurricanes Katrina and Rita. | ||
§ | Cash payments for interest increased $56.2 million year-to-year primarily due to increased borrowings to finance our capital spending program. Our average debt balance for the year ended December 31, 2007 was $6.26 billion compared to $4.93 billion for the year ended December 31, 2006. | ||
§ | Cash payments for federal and state income taxes decreased $4.7 million year-to-year. |
§ | Net borrowings under our consolidated debt agreements increased $1.10 billion year-to-year. In May 2007, EPO sold $700.0 million in principal amount of fixed/floating unsecured junior subordinated notes (Junior Notes B”). In September 2007, EPO sold $800.0 million in principal |
69
Table of Contents
amount of fixed-rate unsecured senior notes (“Senior Notes L”) and in October 2007, EPO repaid $500.0 million in principal amount of Senior Notes E. For information regarding our consolidated debt obligations, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. | |||
§ | Net proceeds from the issuance of our common units decreased $788.0 million year-to-year. We had underwritten equity offerings in March and September of 2006 that generated net proceeds of $750.8 million reflecting the sale of 31,050,000 common units. | ||
§ | Contributions from minority interests increased $275.4 million year-to-year primarily due to the initial public offering of Duncan Energy Partners in February 2007, which generated net proceeds of $290.5 million from the sale of 14,950,000 of its common units. See “Other Items — Initial Public Offering of Duncan Energy Partners” within this Item 7 for additional information regarding this offering. | ||
§ | Cash distributions to our partners increased $137.9 million year-to-year due to an increase in common units outstanding and our quarterly cash distribution rates. | ||
§ | We received $48.9 million from the settlement of treasury lock contracts during the year ended December 31, 2007 related to our interest rate hedging activities. |
§ | Our net cash flows from consolidated businesses (excluding cash payments for interest and taxes and distributions received from unconsolidated affiliates) increased $569.6 million year-to-year. The improvement in cash flow is generally due to increased earnings (see “Results of Operations” within this Item 7) and the timing of related cash collections and disbursements between periods. The $569.6 million year-to-year increase also includes a $93.7 million increase in cash proceeds we received from insurance claims related to certain named storms. | ||
§ | Cash distributions received from unconsolidated affiliates decreased $13.0 million year-to-year primarily due to the lingering effects of Hurricanes Katrina and Rita on our Gulf of Mexico investments during the year ended December 31, 2006. | ||
§ | Cash payments for interest increased $7.9 million year-to-year. Our average debt balance for the year ended December 31, 2006 was $4.93 billion compared to $4.63 billion for the year ended December 31, 2005. | ||
§ | Cash payments for federal and state income taxes increased $5.3 million year-to-year. |
70
Table of Contents
71
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Capital spending for business combinations: | ||||||||||||
Encinal acquisition, excluding non-cash consideration (1) | $ | 114 | $ | 145,197 | $ | — | ||||||
Piceance Basin Gathering System acquisition | 368 | 100,000 | — | |||||||||
South Monco Pipeline System acquisition | 35,000 | — | — | |||||||||
Canadian Enterprise Gas Products acquisition | — | 17,690 | — | |||||||||
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”) | 311 | 12,913 | 68,608 | |||||||||
Additional ownership interests in Mid-America and Seminole pipeline systems | — | — | 25,000 | |||||||||
Other business combinations | — | 700 | 12,618 | |||||||||
Total | 35,793 | 276,500 | 326,602 | |||||||||
Capital spending for property, plant and equipment, net:(2) | ||||||||||||
Growth capital projects (3) | 1,986,157 | 1,148,123 | 719,372 | |||||||||
Sustaining capital projects (4) | 142,096 | 132,455 | 98,077 | |||||||||
Total | 2,128,253 | 1,280,578 | 817,449 | |||||||||
Capital spending for intangible assets: | ||||||||||||
Acquisition of intangible assets | 11,232 | — | — | |||||||||
Total | 11,232 | — | — | |||||||||
Capital spending attributable to unconsolidated affiliates: | ||||||||||||
Investments in unconsolidated affiliates (5) | 343,009 | 127,422 | 88,044 | |||||||||
Total | 343,009 | 127,422 | 88,044 | |||||||||
Total capital spending | $ | 2,518,287 | $ | 1,684,500 | $ | 1,232,095 | ||||||
(1) | Excludes $181.1 million of non-cash consideration paid to the seller in the form of 7,115,844 of our common units. See Note 12 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for additional information regarding our business combinations. | |
(2) | On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. Contributions in aid of construction costs were $57.5 million, $60.5 million and $47.0 million for the years ended December 31, 2007, 2006 and 2005, respectively. | |
(3) | Growth capital projects either result in additional revenue streams from existing assets or expand our asset base through construction of new facilities that will generate additional revenue streams. | |
(4) | Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to and major renewals of existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues. | |
(5) | Fiscal 2007 includes $216.5 million in cash contributions to Cameron Highway Oil Pipeline Company (“Cameron Highway”) to fund our share of the repayment of its debt obligations. |
72
Table of Contents
Actual | Current | |||||||||||
Estimated | Costs Through | Forecast | ||||||||||
Date of | December 31, | Total | ||||||||||
Project Name | Completion | 2007 | Cost | |||||||||
Pioneer II natural gas processing plant | First Quarter 2008 | $ | 279.9 | $ | 360.2 | |||||||
Expansion of Petal natural gas storage facility | Second Quarter 2008 | 65.3 | 96.5 | |||||||||
Meeker II natural gas processing plant | Third Quarter 2008 | 137.5 | 399.5 | |||||||||
Sherman Extension Pipeline (Barnett Shale) | Fourth Quarter 2008 | 30.9 | 477.9 | |||||||||
ExxonMobil Conditioning & Treating Facility — Piceance Basin | Fourth Quarter 2008 | 122.3 | 195.4 | |||||||||
Mont Belvieu Storage Well Optimization Projects | Fourth Quarter 2008 | 131.0 | 180.5 | |||||||||
Shenzi Oil Pipeline | 2009 | 76.2 | 171.2 | |||||||||
Marathon Piceance Basin pipeline projects | 2009 | 3.3 | 114.8 | |||||||||
Expansion of Wilson natural gas storage facility | 2010 | 2.4 | 113.7 |
73
Table of Contents
74
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Expensed | $ | 43,499 | $ | 26,397 | $ | 17,245 | ||||||
Capitalized | 52,420 | 38,180 | 24,964 | |||||||||
Total | $ | 95,919 | $ | 64,577 | $ | 42,209 | ||||||
75
Table of Contents
§ | changes in laws and regulations that limit the estimated economic life of an asset; | ||
§ | changes in technology that render an asset obsolete; | ||
§ | changes in expected salvage values; or | ||
§ | changes in the forecast life of applicable resource basins, if any. |
76
Table of Contents
§ | the expected useful life of the related tangible assets (e.g., fractionation facility, pipeline, etc.); | ||
§ | any legal or regulatory developments that would impact such contractual rights; and | ||
§ | any contractual provisions that enable us to renew or extend such agreements. |
77
Table of Contents
§ | discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins and transportation volumes; | ||
§ | long-term growth rates for cash flows beyond the discrete forecast period; and | ||
§ | appropriate discount rates. |
§ | persuasive evidence of an exchange arrangement exists; | ||
§ | delivery has occurred or services have been rendered; | ||
§ | the buyer’s price is fixed or determinable; and | ||
§ | collectability is reasonably assured. |
78
Table of Contents
79
Table of Contents
We contributed 66% of our equity interests in the following subsidiaries to Duncan Energy Partners: | |||
§ | Mont Belvieu Caverns, 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, 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; | ||
§ | Sabine Propylene, which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana; | ||
§ | Lou-Tex Propylene, which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and | ||
§ | South Texas NGL, 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. |
80
Table of Contents
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 (1) | $ | 6,896,500 | $ | — | $ | 1,091,840 | $ | 1,347,160 | $ | 4,457,500 | ||||||||||
Estimated cash payments for interest (2) | $ | 9,071,523 | $ | 437,686 | $ | 831,740 | $ | 676,622 | $ | 7,125,475 | ||||||||||
Operating lease obligations (3) | $ | 325,705 | $ | 27,785 | $ | 49,172 | $ | 46,922 | $ | 201,826 | ||||||||||
Purchase obligations: (4) | ||||||||||||||||||||
Product purchase commitments: | ||||||||||||||||||||
Estimated payment obligations: | ||||||||||||||||||||
Natural gas | $ | 685,600 | $ | 137,345 | $ | 273,940 | $ | 274,315 | $ | — | ||||||||||
NGLs | $ | 4,041,275 | $ | 697,277 | $ | 830,264 | $ | 830,264 | $ | 1,683,470 | ||||||||||
Petrochemicals | $ | 4,065,675 | $ | 1,751,152 | $ | 1,261,071 | $ | 375,368 | $ | 678,084 | ||||||||||
Other | $ | 60,385 | $ | 31,392 | $ | 17,114 | $ | 3,831 | $ | 8,048 | ||||||||||
Underlying major volume commitments: | ||||||||||||||||||||
Natural gas (in BBtus) | 91,350 | 18,300 | 36,500 | 36,550 | — | |||||||||||||||
NGLs (in MBbls) | 50,798 | 9,745 | 10,172 | 10,172 | 20,709 | |||||||||||||||
Petrochemicals (in MBbls) | 45,207 | 20,115 | 13,704 | 4,097 | 7,291 | |||||||||||||||
Service payment commitments | $ | 8,962 | $ | 6,745 | $ | 1,657 | $ | 186 | $ | 374 | ||||||||||
Capital expenditure commitments (5) | $ | 569,654 | $ | 569,654 | $ | — | $ | — | $ | — | ||||||||||
Other Long-Term Liabilities, as reflected in our Consolidated Balance Sheet (6) | $ | 73,748 | $ | — | $ | 23,680 | $ | 3,229 | $ | 46,839 | ||||||||||
Total | $ | 25,799,027 | $ | 3,659,036 | $ | 4,380,478 | $ | 3,557,897 | $ | 14,201,616 | ||||||||||
(1) | Represents our scheduled future maturities of consolidated debt obligations for the periods indicated. See Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding our debt obligations. | |
(2) | Our estimated cash payments for interest are based on the principle amount of consolidated debt obligations outstanding at December 31, 2007. With respect to variable-rate debt, we applied the weighted-average interest rates paid during 2007. See Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding variable interest rates charged in 2007 under our credit agreements. In addition, our estimate of cash payments for interest gives effect to interest rate swap agreements in place at December 31, 2007. See Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. Our estimated cash payments for interest are significantly influenced by the long-term maturities of our $550.0 million Junior Notes A (due August 2066) and $700.0 million Junior Notes B (due January 2068). Our estimated cash payments for interest assume that the Junior Note obligations are not called prior to maturity. | |
(3) | Primarily represents operating leases for (i) underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, (iii) a railcar unloading terminal in Mont Belvieu, Texas and (iv) land held pursuant to right-of-way agreements. | |
(4) | Represents enforceable and legally binding agreements to purchase goods or services based on the contractual terms of each agreement at December 31, 2007. | |
(5) | Represents our short-term unconditional payment obligations relating to our capital projects. | |
(6) | As presented on our Consolidated Balance Sheet at December 31, 2007, other long-term liabilities consist primarily of (i) liabilities for our asset retirement obligations and (ii) liabilities for environmental remediation costs. For information regarding our environmental remediation costs and asset retirement obligations, see Notes 2 and 10 respectively, of our Notes to Consolidated Financial Statements included under Item 8 of this annual report. |
81
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Revenues from consolidated operations | ||||||||||||
EPCO and affiliates | $ | 362,076 | $ | 98,671 | $ | 311 | ||||||
Unconsolidated affiliates | 290,640 | 304,559 | 367,204 | |||||||||
Total | $ | 652,716 | $ | 403,230 | $ | 367,515 | ||||||
Operating costs and expenses | ||||||||||||
EPCO and affiliates | $ | 329,699 | $ | 311,537 | $ | 293,134 | ||||||
Unconsolidated affiliates | 32,765 | 31,606 | 23,563 | |||||||||
Total | $ | 362,464 | $ | 343,143 | $ | 316,697 | ||||||
General and administrative expenses | ||||||||||||
EPCO and affiliates | $ | 56,518 | $ | 41,265 | $ | 40,954 | ||||||
82
Table of Contents
�� | ||||||||||||
For the Year the Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Total segment gross operating margin | $ | 1,492,068 | $ | 1,362,449 | $ | 1,136,347 | ||||||
Adjustments to reconcile total gross operating margin | ||||||||||||
To operating income: | ||||||||||||
Depreciation, amortization and accretion in operating costs and expenses | (513,840 | ) | (440,256 | ) | (413,441 | ) | ||||||
Operating lease expense paid by EPCO | (2,105 | ) | (2,109 | ) | (2,112 | ) | ||||||
Gain (loss) on sale of assets in operating costs and expenses | (5,391 | ) | 3,359 | 4,488 | ||||||||
General and administrative costs | (87,695 | ) | (63,391 | ) | (62,266 | ) | ||||||
Consolidated operating income | 883,037 | 860,052 | 663,016 | |||||||||
Other expense, net | (303,463 | ) | (229,967 | ) | (225,178 | ) | ||||||
Income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles | $ | 579,574 | $ | 630,085 | $ | 437,838 | ||||||
§ | 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. |
83
Table of Contents
§ | Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements;” | ||
§ | SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51;” and | ||
§ | SFAS 141(R), “Business Combinations.” |
84
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 8.65% | $50 million | |||||
Senior Notes C, 6.375% fixed rate, due Feb. 2013 | 2 | Jan. 2004 to Feb. 2013 | Feb. 2013 | 6.38% to 7.19% | $200 million | |||||
Senior Notes G, 5.6% fixed rate, due Oct. 2014 | 6 | 4th Qtr. 2004 to Oct. 2014 | Oct. 2014 | 5.60% to 6.13% | $600 million | |||||
Senior Notes K, 4.95% fixed rate, due June 2010 | 2 | Aug. 2005 to June 2010 | June 2010 | 4.95% to 5.33% | $200 million | |||||
(1) | The variable rate indicated is the all-in variable rate for the current settlement period. |
Swap Fair Value at | ||||||||||||||||
Resulting | December 31, | December 31, | February 12, | |||||||||||||
Scenario | Classification | 2006 | 2007 | 2008 | ||||||||||||
FV assuming no change in underlying interest rates | Asset (Liability) | $ | (29,060 | ) | $ | 14,839 | $ | 42,544 | ||||||||
FV assuming 10% increase in underlying interest rates | Asset (Liability) | (56,249 | ) | (5,425 | ) | 24,479 | ||||||||||
FV assuming 10% decrease in underlying interest rates | Asset (Liability) | (1,872 | ) | 35,102 | 60,610 |
85
Table of Contents
Number | Period Covered | Termination | Variable to | Notional | ||||||||
Hedged Variable Rate Debt | Of Swaps | by Swap | Date of Swap | Fixed Rate(1) | Value | |||||||
Duncan Energy Partners’ Revolver, due Feb. 2011 | 3 | Sep. 2007 to Sep. 2010 | Sep. 2010 | 4.84% to 4.62% | $175.0 million |
(1) | Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”). |
Swap Fair Value at | ||||||||||||
Resulting | December 31, | February 12, | ||||||||||
Scenario | Classification | 2007 | 2008 | |||||||||
FV assuming no change in underlying interest rates | Liability | $ | 3,782 | $ | 7,749 | |||||||
FV assuming 10% increase in underlying interest rates | Liability | 2,245 | 6,563 | |||||||||
FV assuming 10% decrease in underlying interest rates | Liability | 5,319 | 8,934 |
86
Table of Contents
Notional | Cash | |||||||
Amount | Gain | |||||||
Second quarter of 2006 additions to portfolio (1) | $ | 250.0 | $ | — | ||||
Third quarter of 2006 additions to portfolio (1) | 50.0 | — | ||||||
Third quarter of 2006 terminations (2) | (300.0 | ) | — | |||||
Fourth quarter of 2006 additions to portfolio (3) | 562.5 | — | ||||||
Treasury lock portfolio, December 31, 2006 (4) | 562.5 | — | ||||||
First quarter of 2007 additions to portfolio (3) | 437.5 | — | ||||||
Second quarter of 2007 terminations (5) | (875.0 | ) | 42.3 | |||||
Third quarter of 2007 additions to portfolio (6) | 875.0 | — | ||||||
Third quarter of 2007 terminations (7) | (750.0 | ) | 6.6 | |||||
Fourth quarter of 2007 additions to portfolio (8) | 350.0 | — | ||||||
Treasury lock portfolio, December 31, 2007 (4) | $ | 600.0 | $ | 48.9 | ||||
(1) | EPO entered into these transactions related to its anticipated issuances of debt in 2006. | |
(2) | Terminations relate to the issuance of the Junior Notes A ($300.0 million). | |
(3) | EPO entered into these transactions related to its anticipated issuances of debt in 2007. | |
(4) | The fair value of open financial instruments at December 31, 2006 and 2007 was an asset of $11.2 million and a liability of $19.6 million, respectively. | |
(5) | Terminations relate to the issuance of the Junior Notes B ($500.0 million) and Senior Notes L ($375.0 million). Of the $42.3 million gain, $10.6 million relates to the Junior Notes B and the remainder to the Senior Notes L and its successor debt. | |
(6) | EPO entered into these transactions related to its issuance of the Senior Notes L (including its successor debt) in August 2007 ($500.0 million) and anticipated issuance of debt during the first half of 2008 ($250.0 million) | |
(7) | Terminations relate to the issuance of the Senior Notes L and its successor debt. | |
(8) | EPO entered into these transactions in anticipated issuance of debt during the first half of 2008. |
87
Table of Contents
Resulting | Commodity Financial Instrument Portfolio FV | |||||||||||||||
Scenario | Classification | December 31, 2006 | December 31, 2007 | February 12, 2008 | ||||||||||||
FV assuming no change in underlying commodity prices | Asset (Liability) | $ | (3,184 | ) | $ | (19,305 | ) | $ | 25,941 | |||||||
FV assuming 10% increase in underlying commodity prices | Asset (Liability) | (2,119 | ) | 9,903 | 52,974 | |||||||||||
FV assuming 10% decrease in underlying commodity prices | Liability | (4,249 | ) | (48,513 | ) | (1,114 | ) |
88
INDEX TO FINANCIAL STATEMENTS
Page No. | ||
90 | ||
91 | ||
92 | ||
93 | ||
94 | ||
95 | ||
96 | ||
97 | ||
105 | ||
106 | ||
108 | ||
114 | ||
115 | ||
119 | ||
121 | ||
122 | ||
124 | ||
129 | ||
132 | ||
135 | ||
141 | ||
145 | ||
149 | ||
157 | ||
159 | ||
160 | ||
164 | ||
167 | ||
168 | ||
168 | ||
170 |
89
Table of Contents
Unitholders of Enterprise Products Partners L.P.
Houston, Texas
February 28, 2008
90
Table of Contents
December 31, | ||||||||
2007 | 2006 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 39,722 | $ | 22,619 | ||||
Restricted cash | 53,144 | 23,667 | ||||||
Accounts and notes receivable — trade, net of allowance for doubtful accounts of $21,659 at December 31, 2007 and $23,406 at December 31, 2006 | 1,930,762 | 1,306,290 | ||||||
Accounts receivable — related parties | 79,782 | 16,738 | ||||||
Inventories | 354,282 | 423,844 | ||||||
Prepaid and other current assets | 80,193 | 129,000 | ||||||
Total current assets | 2,537,885 | 1,922,158 | ||||||
Property, plant and equipment, net | 11,587,264 | 9,832,547 | ||||||
Investments in and advances to unconsolidated affiliates | 858,339 | 564,559 | ||||||
Intangible assets, net of accumulated amortization of $341,494 at December 31, 2007 and $251,876 at December 31, 2006 | 917,000 | 1,003,955 | ||||||
Goodwill | 591,652 | 590,541 | ||||||
Deferred tax asset | 3,522 | 1,855 | ||||||
Other assets | 112,345 | 74,103 | ||||||
Total assets | $ | 16,608,007 | $ | 13,989,718 | ||||
LIABILITIES AND PARTNERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable — trade | $ | 324,999 | $ | 277,070 | ||||
Accounts payable — related parties | 24,432 | 6,785 | ||||||
Accrued product payables | 2,227,489 | 1,364,493 | ||||||
Accrued expenses | 47,756 | 35,763 | ||||||
Accrued interest | 130,971 | 90,865 | ||||||
Other current liabilities | 289,036 | 209,945 | ||||||
Total current liabilities | 3,044,683 | 1,984,921 | ||||||
Long-term debt: (see Note 14) | ||||||||
Senior debt obligations — principal | 5,646,500 | 4,779,068 | ||||||
Junior subordinated notes — principal | 1,250,000 | 550,000 | ||||||
Other | 9,645 | (33,478 | ) | |||||
Total long-term debt | 6,906,145 | 5,295,590 | ||||||
Deferred tax liabilities | 21,364 | 13,723 | ||||||
Other long-term liabilities | 73,748 | 86,121 | ||||||
Minority interest | 430,418 | 129,130 | ||||||
Commitments and contingencies | ||||||||
Partners’ equity: | ||||||||
Limited Partners | ||||||||
Common units (433,608,763 units outstanding at December 31, 2007 and 431,303,193 units outstanding at December 31, 2006 ) | 5,976,947 | 6,320,577 | ||||||
Restricted common units (1,688,540 units outstanding at December 31, 2007 and 1,105,237 units outstanding at December 31, 2006) | 15,948 | 9,340 | ||||||
General partner | 122,297 | 129,175 | ||||||
Accumulated other comprehensive income | 16,457 | 21,141 | ||||||
Total partners’ equity | 6,131,649 | 6,480,233 | ||||||
Total liabilities and partners’ equity | $ | 16,608,007 | $ | 13,989,718 | ||||
91
Table of Contents
For Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Revenues: | ||||||||||||
Third parties | $ | 16,297,409 | $ | 13,587,739 | $ | 11,889,444 | ||||||
Related parties | 652,716 | 403,230 | 367,515 | |||||||||
Total (see Note 16) | 16,950,125 | 13,990,969 | 12,256,959 | |||||||||
Costs and expenses: | ||||||||||||
Operating costs and expenses | ||||||||||||
Third parties | 15,646,587 | 12,745,948 | 11,229,528 | |||||||||
Related parties | 362,464 | 343,143 | 316,697 | |||||||||
Total operating costs and expenses | 16,009,051 | 13,089,091 | 11,546,225 | |||||||||
General and administrative costs | ||||||||||||
Third parties | 31,177 | 22,126 | 21,312 | |||||||||
Related parties | 56,518 | 41,265 | 40,954 | |||||||||
Total general and administrative costs | 87,695 | 63,391 | 62,266 | |||||||||
Total costs and expenses | 16,096,746 | 13,152,482 | 11,608,491 | |||||||||
Equity in income of unconsolidated affiliates | 29,658 | 21,565 | 14,548 | |||||||||
Operating income | 883,037 | 860,052 | 663,016 | |||||||||
Other income (expense): | ||||||||||||
Interest expense | (311,764 | ) | (238,023 | ) | (230,549 | ) | ||||||
Interest income | 8,601 | 7,589 | 5,237 | |||||||||
Other, net | (300 | ) | 467 | 134 | ||||||||
Other expense | (303,463 | ) | (229,967 | ) | (225,178 | ) | ||||||
Income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles | 579,574 | 630,085 | 437,838 | |||||||||
Provision for income taxes | (15,257 | ) | (21,323 | ) | (8,362 | ) | ||||||
Income before minority interest and the cumulative effect of changes in accounting principles | 564,317 | 608,762 | 429,476 | |||||||||
Minority interest | (30,643 | ) | (9,079 | ) | (5,760 | ) | ||||||
Income before the cumulative effect of changes in accounting principles | 533,674 | 599,683 | 423,716 | |||||||||
Cumulative effect of changes in accounting principles (see Note 8) | — | 1,472 | (4,208 | ) | ||||||||
Net income | $ | 533,674 | $ | 601,155 | $ | 419,508 | ||||||
Net income allocation:(see Note 15) | ||||||||||||
Limited partners’ interest in net income | $ | 417,728 | $ | 504,156 | $ | 348,512 | ||||||
General partner interest in net income | $ | 115,946 | $ | 96,999 | $ | 70,996 | ||||||
Earnings per unit:(see Note 19) | ||||||||||||
Basic and diluted income per unit before changes in accounting principles | $ | 0.96 | $ | 1.22 | $ | 0.92 | ||||||
Basic and diluted income per unit | $ | 0.96 | $ | 1.22 | $ | 0.91 | ||||||
92
Table of Contents
For Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Net income | $ | 533,674 | $ | 601,155 | $ | 419,508 | ||||||
Other comprehensive income: | ||||||||||||
Cash flow hedges: | ||||||||||||
Net commodity financial instrument losses during period | (17,997 | ) | (3,622 | ) | — | |||||||
Foreign currency hedge gains | 1,308 | — | — | |||||||||
Less: Reclassification adjustment for gain included in net income related to commodity financial instruments | — | — | (1,434 | ) | ||||||||
Net interest rate financial instrument gains during period | 14,375 | 11,196 | — | |||||||||
Less: Amortization of cash flow financing hedges | (5,429 | ) | (4,234 | ) | (4,048 | ) | ||||||
Total cash flow hedges | (7,743 | ) | 3,340 | (5,482 | ) | |||||||
Change in funded status of Dixie benefit plans, net of tax | (52 | ) | — | — | ||||||||
Foreign currency translation adjustment | 2,007 | (807 | ) | — | ||||||||
Total other comprehensive income | (5,788 | ) | 2,533 | (5,482 | ) | |||||||
Comprehensive income | $ | 527,886 | $ | 603,688 | $ | 414,026 | ||||||
93
Table of Contents
For Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Operating activities: | ||||||||||||
Net income | $ | 533,674 | $ | 601,155 | $ | 419,508 | ||||||
Adjustments to reconcile net income to net cash flows provided by operating activities: | ||||||||||||
Depreciation, amortization and accretion in operating costs and expenses | 513,840 | 440,256 | 413,441 | |||||||||
Depreciation and amortization in general and administrative costs | 10,258 | 7,186 | 7,184 | |||||||||
Amortization in interest expense | (336 | ) | 766 | 152 | ||||||||
Equity in income of unconsolidated affiliates | (29,658 | ) | (21,565 | ) | (14,548 | ) | ||||||
Distributions received from unconsolidated affiliates | 73,593 | 43,032 | 56,058 | |||||||||
Provision for impairment of long-lived asset | — | 88 | — | |||||||||
Cumulative effect of changes in accounting principles | — | (1,472 | ) | 4,208 | ||||||||
Operating lease expense paid by EPCO, Inc. | 2,105 | 2,109 | 2,112 | |||||||||
Minority interest | 30,643 | 9,079 | 5,760 | |||||||||
Loss (gain) on sale of assets | 5,391 | (3,359 | ) | (4,488 | ) | |||||||
Deferred income tax expense | 8,306 | 14,427 | 8,594 | |||||||||
Changes in fair market value of financial instruments | 981 | (51 | ) | 122 | ||||||||
Non-cash pension expense | 588 | — | — | |||||||||
Loss on early extinguishment of debt | 250 | — | — | |||||||||
Net effect of changes in operating accounts (see Note 22) | 441,306 | 83,418 | (266,395 | ) | ||||||||
Net cash flows provided by operating activities | 1,590,941 | 1,175,069 | 631,708 | |||||||||
Investing activities: | ||||||||||||
Capital expenditures | (2,185,800 | ) | (1,341,070 | ) | (864,453 | ) | ||||||
Contributions in aid of construction costs | 57,547 | 60,492 | 47,004 | |||||||||
Proceeds from sale of assets | 12,027 | 3,927 | 44,746 | |||||||||
Decrease (increase) in restricted cash | (47,347 | ) | (8,715 | ) | 11,204 | |||||||
Cash used for business combinations (see Note 12) | (35,793 | ) | (276,500 | ) | (326,602 | ) | ||||||
Acquisition of intangible assets | (11,232 | ) | — | (1,750 | ) | |||||||
Investments in unconsolidated affiliates | (332,909 | ) | (138,266 | ) | (87,342 | ) | ||||||
Advances from (to) unconsolidated affiliates | (10,100 | ) | 10,844 | (702 | ) | |||||||
Return of investment from unconsolidated affiliate | — | — | 47,500 | |||||||||
Cash used in investing activities | (2,553,607 | ) | (1,689,288 | ) | (1,130,395 | ) | ||||||
Financing activities: | ||||||||||||
Borrowings under debt agreements | 6,024,518 | 3,378,285 | 4,192,345 | |||||||||
Repayments of debt | (4,458,141 | ) | (2,907,000 | ) | (3,630,611 | ) | ||||||
Debt issuance costs | (16,511 | ) | (8,955 | ) | (9,297 | ) | ||||||
Distributions paid to partners | (957,705 | ) | (843,292 | ) | (716,699 | ) | ||||||
Distributions paid to minority interests | (32,326 | ) | (8,831 | ) | (5,724 | ) | ||||||
Contributions from Duncan Energy Partners reflected as part of minority interests (see Notes 2 and 17) | 290,466 | — | — | |||||||||
Other contributions from minority interests | 12,506 | 27,578 | 39,110 | |||||||||
Contributions from general partner related to issuance of restricted units | — | — | 177 | |||||||||
Net proceeds from issuance of common units | 69,221 | 857,187 | 646,928 | |||||||||
Repurchase of restricted units and options | (1,568 | ) | — | — | ||||||||
Settlement of treasury lock contracts | 48,895 | — | — | |||||||||
Cash provided by financing activities | 979,355 | 494,972 | 516,229 | |||||||||
Effect of exchange rate changes on cash | 414 | (232 | ) | — | ||||||||
Net change in cash and cash equivalents | 16,689 | (19,247 | ) | 17,542 | ||||||||
Cash and cash equivalents, January 1 | 22,619 | 42,098 | 24,556 | |||||||||
Cash and cash equivalents, December 31 | $ | 39,722 | $ | 22,619 | $ | 42,098 | ||||||
94
Table of Contents
(See Note 15 for Unit History and Detail of Changes in Limited Partners’ Equity)
(Dollars in thousands)
Limited | General | Treasury | Deferred | |||||||||||||||||||||
Partners | Partner | units | Comp. | AOCI | Total | |||||||||||||||||||
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 8) | (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 15) | (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 | ||||||||||||||||||
Net income | 417,728 | 115,946 | — | — | — | 533,674 | ||||||||||||||||||
Operating leases paid by EPCO, Inc. | 2,063 | 42 | — | — | — | 2,105 | ||||||||||||||||||
Cash distributions to partners | (833,793 | ) | (124,388 | ) | — | — | — | (958,181 | ) | |||||||||||||||
Unit option reimbursements to EPCO, Inc. | (2,999 | ) | (58 | ) | — | — | — | (3,057 | ) | |||||||||||||||
Net proceeds from sales of common units | 60,445 | 1,232 | — | — | — | 61,677 | ||||||||||||||||||
Proceeds from exercise of unit options | 7,549 | 154 | — | — | — | 7,703 | ||||||||||||||||||
Repurchase of restricted units and options | (1,568 | ) | — | — | — | — | (1,568 | ) | ||||||||||||||||
Change in funded status of pension and postretirement plans, net of tax | — | — | — | — | 1,052 | 1,052 | ||||||||||||||||||
Amortization of equity awards | 13,553 | 194 | — | — | — | 13,747 | ||||||||||||||||||
Foreign currency translation adjustment | — | — | — | — | 2,007 | 2,007 | ||||||||||||||||||
Cash flow hedges | — | — | — | — | (7,743 | ) | (7,743 | ) | ||||||||||||||||
Balance, December 31, 2007 | $ | 5,992,895 | $ | 122,297 | $ | — | $ | — | $ | 16,457 | $ | 6,131,649 | ||||||||||||
95
Table of Contents
96
Table of Contents
For the Years Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Balance at beginning of period | $ | 23,406 | $ | 37,329 | $ | 32,773 | ||||||
Charges to expense | 2,614 | 473 | 5,391 | |||||||||
Acquisition-related additions and other | — | — | 5,541 | |||||||||
Deductions | (4,361 | ) | (14,396 | ) | (6,376 | ) | ||||||
Balance at end of period | $ | 21,659 | $ | 23,406 | $ | 37,329 | ||||||
97
Table of Contents
98
Table of Contents
For the Years Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Balance at beginning of period | $ | 24,178 | $ | 22,090 | $ | 22,119 | ||||||
Charges to expense | 375 | 1,105 | 139 | |||||||||
Acquisition-related additions and other | 6,499 | 8,811 | — | |||||||||
Deductions | (4,593 | ) | (7,828 | ) | (168 | ) | ||||||
Balance at end of period | $ | 26,459 | $ | 24,178 | $ | 22,090 | ||||||
99
Table of Contents
100
Table of Contents
101
Table of Contents
102
Table of Contents
103
Table of Contents
Reported net income | $ | 419,508 | ||
Additional unit option-based compensation expense estimated using fair value-based method | (708 | ) | ||
Reduction in compensation expense related to Employee Partnership equity awards | 1,271 | |||
Pro forma net income | $ | 420,071 | ||
Basic and diluted earnings per unit: | ||||
As reported | $ | 0.91 | ||
Pro forma | $ | 0.91 | ||
104
Table of Contents
§ | Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree. | ||
§ | Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any noncontrolling interest in the acquiree, and requires the acquirer to recognize that excess in earnings as a gain attributable to the acquirer. | ||
§ | Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. |
105
Table of Contents
106
Table of Contents
107
Table of Contents
For the Years Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
EPCO 1998 Long-Term Incentive Plan (“1998 Plan”) | ||||||||||||
Unit options | $ | 4,447 | $ | 701 | $ | — | ||||||
Restricted units | 7,721 | 5,019 | 3,776 | |||||||||
Total 1998 Plan (1) | 12,168 | 5,720 | 3,776 | |||||||||
Employee Partnerships | 3,911 | 2,146 | 2,043 | |||||||||
DEP Holdings, LLC Unit Appreciation Rights | 69 | — | — | |||||||||
Total consolidated expense | $ | 16,148 | $ | 7,866 | $ | 5,819 | ||||||
(1) | Amounts for the year ended December 31, 2007 include $4.6 million associated with the resignation of our former chief executive officer. |
108
Table of Contents
109
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, 2004 | 2,463,000 | $ | 18.84 | |||||||||||||
Granted (2) | 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 (3) | 590,000 | 24.85 | ||||||||||||||
Exercised | (211,000 | ) | 15.95 | |||||||||||||
Forfeited | (45,000 | ) | 24.28 | |||||||||||||
Outstanding at December 31, 2006 | 2,416,000 | 23.32 | ||||||||||||||
Granted (4) | 895,000 | 30.63 | ||||||||||||||
Exercised | (256,000 | ) | 19.26 | |||||||||||||
Settled or forfeited (5) | (740,000 | ) | 24.62 | |||||||||||||
Outstanding at December 31, 2007(6) | 2,315,000 | 26.18 | 7.73 | $ | 3,291 | |||||||||||
Options exercisable at: | ||||||||||||||||
December 31, 2005 | 727,000 | $ | 19.19 | 5.54 | $ | 3,503 | ||||||||||
December 31, 2006 | 591,000 | $ | 20.85 | 5.11 | $ | 4,808 | ||||||||||
December 31, 2007 (6) | 335,000 | $ | 22.06 | 3.96 | $ | 3,291 | ||||||||||
(1) | Aggregate intrinsic value reflects fully vested unit options at the date indicated. | |
(2) | The total grant date fair value of these awards was $0.7 million based on the following assumptions: (i) weighted-average expected life of options of seven years; (ii) weighted-average risk-free interest rate of 4.2%; (iii) weighted-average expected distribution yield on our common units of 9.2%; and (iv) weighted-average expected unit price volatility on our common units of 20.0%. | |
(3) | The total grant date fair value of these awards was $1.2 million based on the following assumptions: (i) weighted-average expected life of options of seven years; (ii) weighted-average risk-free interest rate of 5.0%; (iii) weighted-average expected distribution yield on our common units of 8.9%; and (iv) weighted-average expected unit price volatility on our common units of 23.5%. | |
(4) | The total grant date fair value of these awards was $2.4 million based on the following assumptions: (i) expected life of options of seven years; (ii) weighted-average risk-free interest rate of 4.8%; (iii) weighted-average expected distribution yield on our common units of 8.4%; and (iv) weighted-average expected unit price volatility on our common units of 23.2%. | |
(5) | Includes the settlement of 710,000 options in connection with the resignation of our former chief executive officer. | |
(6) | We were committed to issue 2,315,000 and 2,416,000 of our common units at December 31, 2007 and 2006, respectively, if all outstanding options awarded under the 1998 Plan (as of these dates) were exercised. An additional 285,000, 380,000, 510,000 and 805,000 of these options are exercisable in 2008, 2009, 2010 and 2011, respectively. |
110
Table of Contents
Weighted- | ||||||||
Average Grant | ||||||||
Number of | Date Fair Value | |||||||
Units | per Unit(1) | |||||||
Restricted units at December 31, 2004 | 488,525 | |||||||
Granted (2) | 362,011 | $ | 26.43 | |||||
Vested | (6,484 | ) | $ | 22.00 | ||||
Forfeited | (92,448 | ) | $ | 24.03 | ||||
Restricted units at December 31, 2005 | 751,604 | |||||||
Granted (3) | 466,400 | $ | 25.21 | |||||
Vested | (42,136 | ) | $ | 24.02 | ||||
Forfeited | (70,631 | ) | $ | 22.86 | ||||
Restricted units at December 31, 2006 | 1,105,237 | |||||||
Granted (4) | 738,040 | $ | 25.61 | |||||
Vested | (4,884 | ) | $ | 25.28 | ||||
Forfeited | (36,800 | ) | $ | 23.51 | ||||
Settled (5) | (113,053 | ) | $ | 23.24 | ||||
Restricted units at December 31, 2007 | 1,688,540 | |||||||
(1) | Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued. | |
(2) | 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%. | |
(3) | 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%. | |
(4) | Aggregate grant date fair value of restricted unit awards issued during 2007 was $18.9 million based on grant date market prices of our common units ranging from $28.00 to $31.83 per unit and estimated forfeiture rates ranging from 4.6% to 17.0%. | |
(5) | Reflects the settlement of restricted units in connection with the resignation of our former chief executive officer. |
111
Table of Contents
112
Table of Contents
§ | Distributions of Cash flow-Each quarter, 100% of the cash distributions received by EPE Unit III from Enterprise GP Holdings will be distributed to the Class A limited partner until it has received an amount equal to the pro rata Class A preferred return (as defined below), and any remaining distributions received by EPE Unit III will be distributed to the Class B limited partners. The Class A preferred return equals 3.797% per annum, of the Class A limited partner’s capital base. The Class A limited partner’s capital base equals approximately $170.0 million plus any unpaid Class A preferred return from prior periods, less any distributions made by EPE Unit III of proceeds from the sale of Enterprise GP Holdings’ units owned by EPE Unit III (as described below). | ||
§ | Liquidating Distributions-Upon liquidation of EPE Unit III, Enterprise GP Holdings’ units having a fair market value equal to the Class A limited partner capital base will be distributed to a private company affiliate of EPCO, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining units of Enterprise GP Holdings will be distributed to the Class B limited partners. | ||
§ | Sale Proceeds-If EPE Unit III sells any of the 4,421,326 units of Enterprise GP Holdings 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. |
113
Table of Contents
Pension | Postretirement | |||||||||||
Plan | Plan | |||||||||||
Projected benefit obligation | $ | 7,250 | $ | 5,882 | ||||||||
Accumulated benefit obligation | 4,971 | — | ||||||||||
Fair value of plan assets | 5,572 | — | ||||||||||
Unfunded liability | 1,678 | 5,882 | ||||||||||
Funded status (liability) | 1,678 | 5,882 |
114
Table of Contents
Pension | Postretirement | |||||||||||
Plan | Plan | |||||||||||
2008 | $ | 218 | $ | 389 | ||||||||
2009 | 287 | 422 | ||||||||||
2010 | 324 | 467 | ||||||||||
2011 | 518 | 505 | ||||||||||
2012 | 534 | 497 | ||||||||||
2013 through 2017 | 3,779 | 2,353 | ||||||||||
Total | $ | 5,660 | $ | 4,633 | ||||||||
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 |
At December 31, | ||||||||
2007 | 2006 | |||||||
Unrecognized transition obligation | $ | 1.0 | $ | 1.2 | ||||
Net of tax | 0.6 | 0.7 | ||||||
Unrecognized prior service cost credit | (1.2 | ) | (1.5 | ) | ||||
Net of tax | (0.8 | ) | (0.9 | ) | ||||
Unrecognized net actuarial loss | 2.8 | 3.1 | ||||||
Net of tax | 1.7 | 1.9 |
115
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 8.65% | $50 million | |||||||||||||||
Senior Notes C, 6.375% fixed rate, due Feb. 2013 | 2 | Jan. 2004 to Feb. 2013 | Feb. 2013 | 6.38% to 7.19% | $200 million | |||||||||||||||
Senior Notes G, 5.6% fixed rate, due Oct. 2014 | 6 | 4th Qtr. 2004 to Oct. 2014 | Oct. 2014 | 5.60% to 6.13% | $600 million | |||||||||||||||
Senior Notes K, 4.95% fixed rate, due June 2010 | 2 | Aug. 2005 to June 2010 | June 2010 | 4.95% to 5.33% | $200 million | |||||||||||||||
(1) | The variable rate indicated is the all-in variable rate for the current settlement period. |
116
Table of Contents
Number | Period Covered | Termination | Variable to | Notional | ||||||
Hedged Variable Rate Debt | Of Swaps | by Swap | Date of Swap | Fixed Rate(1) | Value | |||||
Duncan Energy Partners’ Revolver, due Feb. 2011 | 3 | Sep. 2007 to Sep. 2010 | Sep. 2010 | 4.84% to 4.62% | $175.0 million |
(1) | Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”). |
117
Table of Contents
Notional | Cash | |||||||
Amount | Gain | |||||||
Second quarter of 2006 additions to portfolio (1) | $ | 250.0 | $ | — | ||||
Third quarter of 2006 additions to portfolio (1) | 50.0 | — | ||||||
Third quarter of 2006 terminations (2) | (300.0 | ) | — | |||||
Fourth quarter of 2006 additions to portfolio (3) | 562.5 | — | ||||||
Treasury lock portfolio, December 31, 2006 (4) | 562.5 | — | ||||||
First quarter of 2007 additions to portfolio (3) | 437.5 | — | ||||||
Second quarter of 2007 terminations (5) | (875.0 | ) | 42.3 | |||||
Third quarter of 2007 additions to portfolio (6) | 875.0 | — | ||||||
Third quarter of 2007 terminations (7) | (750.0 | ) | 6.6 | |||||
Fourth quarter of 2007 additions to portfolio (8) | 350.0 | — | ||||||
Treasury lock portfolio, December 31, 2007 (4) | $ | 600.0 | $ | 48.9 | ||||
(1) | EPO entered into these transactions related to its anticipated issuances of debt in 2006. | |
(2) | Terminations relate to the issuance of the Junior Notes A ($300.0 million). | |
(3) | EPO entered into these transactions related to its anticipated issuances of debt in 2007. | |
(4) | The fair value of open financial instruments at December 31, 2006 and 2007 was an asset of $11.2 million and a liability of $19.6 million, respectively. | |
(5) | Terminations relate to the issuance of the Junior Notes B ($500.0 million) and Senior Notes L ($375.0 million). Of the $42.3 million gain, $10.6 million relates to the Junior Notes B and the remainder to the Senior Notes L and its successor debt. | |
(6) | EPO entered into these transactions related to its issuance of the Senior Notes L (including its successor debt) in August 2007 ($500.0 million) and anticipated issuance of debt during the first half of 2008 ($250.0 million). | |
(7) | Terminations relate to the issuance of the Senior Notes L and its successor debt. | |
(8) | EPO entered into these transactions in anticipated issuance of debt during the first half of 2008. |
118
Table of Contents
At December 31, 2007 | At December 31, 2006 | |||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Financial Instruments | Value | Value | Value | Value | ||||||||||||
Financial assets: | ||||||||||||||||
Cash and cash equivalents | $ | 92,866 | $ | 92,866 | $ | 46,286 | $ | 46,286 | ||||||||
Accounts receivable | 2,010,544 | 2,010,544 | 1,323,028 | 1,323,028 | ||||||||||||
Commodity financial instruments (1) | 338 | 338 | 1,472 | 1,472 | ||||||||||||
Foreign currency hedging financial instruments (2) | 1,308 | 1,308 | — | — | ||||||||||||
Interest rate hedging financial instruments (3) | 14,839 | 14,839 | 11,203 | 11,203 | ||||||||||||
Financial liabilities: | ||||||||||||||||
Accounts payable and accrued expenses | 2,755,647 | 2,755,647 | 1,774,976 | 1,774,976 | ||||||||||||
Fixed-rate debt (principal amount) | 5,904,000 | 5,867,899 | 4,909,068 | 4,955,176 | ||||||||||||
Variable-rate debt | 992,500 | 992,500 | 420,000 | 420,000 | ||||||||||||
Commodity financial instruments (1) | 19,643 | 19,643 | 4,655 | 4,655 | ||||||||||||
Foreign currency hedging financial instruments (2) | 27 | 27 | — | — | ||||||||||||
Interest rate hedging financial instruments (3) | 23,422 | 23,422 | 29,060 | 29,060 |
(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) | Relates to the hedging of our exposure to fluctuations in the Canadian dollar. | |
(3) | 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. |
119
Table of Contents
120
Table of Contents
For the Years Ended | ||||||||
December 31, | ||||||||
2006 | 2005 | |||||||
Pro Forma income statement amounts: | ||||||||
Historical net income | $ | 601,155 | $ | 419,508 | ||||
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 | ) | |||||
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 | ) | |||||
Pro forma net income | 599,683 | 423,544 | ||||||
EPGP interest | (96,969 | ) | (71,077 | ) | ||||
Pro forma net income available to limited partners | $ | 502,714 | $ | 352,467 | ||||
Pro forma per unit data (basic): | ||||||||
Historical units outstanding | 414,442 | 382,463 | ||||||
Per unit data: | ||||||||
As reported | $ | 1.22 | $ | 0.91 | ||||
Pro forma | $ | 1.21 | $ | 0.92 | ||||
Pro forma per unit data (diluted): | ||||||||
Historical units outstanding | 414,759 | 382,963 | ||||||
Per unit data: | ||||||||
As reported | $ | 1.22 | $ | 0.91 | ||||
Pro forma | $ | 1.21 | $ | 0.92 | ||||
At December 31, | ||||||||
2007 | 2006 | |||||||
Working inventory (1) | $ | 342,589 | $ | 387,973 | ||||
Forward-sales inventory (2) | 11,693 | 35,871 | ||||||
Total inventory | $ | 354,282 | $ | 423,844 | ||||
(1) | Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services. | |
(2) | Forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts. |
121
Table of Contents
§ | 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. |
Estimated | ||||||||||||
Useful Life | At December 31, | |||||||||||
in Years | 2007 | 2006 | ||||||||||
Plants and pipelines (1) | 3-35 | (5) | $ | 10,884,819 | $ | 8,774,683 | ||||||
Underground and other storage facilities (2) | 5-35 | (6) | 720,795 | 596,649 | ||||||||
Platforms and facilities (3) | 23-31 | 637,812 | 161,839 | |||||||||
Transportation equipment (4) | 3-10 | 32,627 | 27,008 | |||||||||
Land | 48,172 | 40,010 | ||||||||||
Construction in progress | 1,173,988 | 1,734,083 | ||||||||||
Total | 13,498,213 | 11,334,272 | ||||||||||
Less accumulated depreciation | 1,910,949 | 1,501,725 | ||||||||||
Property, plant and equipment, net | $ | 11,587,264 | $ | 9,832,547 | ||||||||
(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). |
122
Table of Contents
For the Years Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Depreciation expense (1) | $ | 414,901 | $ | 350,832 | $ | 328,736 | ||||||
Capitalized interest (2) | $ | 75,476 | $ | 55,660 | $ | 22,046 |
(1) | Depreciation expense is a component of operating costs and expenses as presented in our Statements of Consolidated Operations. | |
(2) | Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded. |
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 | |||
Liabilities incurred | 1,673 | |||
Liabilities settled | (5,069 | ) | ||
Revisions in estimated cash flows | 15,645 | |||
Accretion expense | 3,962 | |||
Asset retirement obligation liability balance, December 31, 2007 | $ | 40,614 | ||
123
Table of Contents
Ownership | Investments in and advances to | |||||||||||
Percentage at | Unconsolidated Affiliates at | |||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2007 | 2006 | ||||||||||
NGL Pipelines & Services: | ||||||||||||
VESCO | 13.1 | % | $ | 40,129 | $ | 39,618 | ||||||
K/D/S Promix, L.L.C. (“Promix”) | 50 | % | 51,537 | 46,140 | ||||||||
Baton Rouge Fractionators LLC (“BRF”) | 32.3 | % | 25,423 | 25,471 | ||||||||
Onshore Natural Gas Pipelines & Services: | ||||||||||||
Jonah Gas Gathering Company (“Jonah”) | 19.4 | % | 235,837 | 120,370 | ||||||||
Evangeline (1) | 49.5 | % | 3,490 | 4,221 | ||||||||
Offshore Pipelines & Services: | ||||||||||||
Poseidon Oil Pipeline, L.L.C. (“Poseidon”) | 36 | % | 58,423 | 62,324 | ||||||||
Cameron Highway Oil Pipeline Company (“Cameron Highway”) (2) | 50 | % | 256,588 | 60,216 | ||||||||
Deepwater Gateway, L.L.C. (“Deepwater Gateway”) | 50 | % | 111,221 | 117,646 | ||||||||
Neptune Pipeline Company, L.L.C. (“Neptune”) (3) | 25.7 | % | 55,468 | 58,789 | ||||||||
Nemo Gathering Company, LLC (“Nemo”) (4) | 33.9 | % | 2,888 | 11,161 | ||||||||
Petrochemical Services: | ||||||||||||
Baton Rouge Propylene Concentrator, LLC (“BRPC”) | 30 | % | 13,282 | 13,912 | ||||||||
La Porte (5) | 50 | % | 4,053 | 4,691 | ||||||||
Total | $ | 858,339 | $ | 564,559 | ||||||||
(1) | Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. | |
(2) | During the year ended December 31, 2007, we contributed $216.5 million to Cameron Highway to fund our portion of the repayment of Cameron Highway’s debt. | |
(3) | The December 31, 2006 amount includes a $7.4 million non-cash impairment charge attributable to our investment in Neptune. | |
(4) | The December 31, 2007 amount includes a $7.0 million non-cash impairment charge attributable to our investment in Nemo. | |
(5) | Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively. |
124
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
NGL Pipelines & Services: | ||||||||||||
Dixie | $ | — | $ | — | $ | 1,103 | ||||||
VESCO | 3,507 | 1,719 | 1,412 | |||||||||
Belle Rose | — | — | (151 | ) | ||||||||
Promix | 514 | 1,353 | 1,876 | |||||||||
BRF | 2,010 | 2,643 | 1,313 | |||||||||
Onshore Natural Gas Pipelines & Services: | ||||||||||||
Evangeline | 183 | 958 | 331 | |||||||||
Coyote | — | 1,676 | 2,053 | |||||||||
Jonah | 9,357 | 238 | — | |||||||||
Offshore Pipelines & Services: | ||||||||||||
Poseidon | 10,020 | 11,310 | 7,279 | |||||||||
Cameron Highway (1) | (11,200 | ) | (11,000 | ) | (15,872 | ) | ||||||
Deepwater Gateway | 20,606 | 18,392 | 10,612 | |||||||||
Neptune (2) | (821 | ) | (8,294 | ) | 2,019 | |||||||
Nemo (3) | (5,977 | ) | 1,501 | 1,774 | ||||||||
Starfish Pipeline Company, LLC (“Starfish”) (4) | — | — | 313 | |||||||||
Petrochemical Services: | ||||||||||||
BRPC | 2,266 | 1,864 | 1,224 | |||||||||
La Porte | (807 | ) | (795 | ) | (738 | ) | ||||||
Total | $ | 29,658 | $ | 21,565 | $ | 14,548 | ||||||
(1) | 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. | |
(2) | Equity earnings from Neptune for 2006 include a $7.4 million non-cash impairment charge. | |
(3) | Equity earnings from Nemo for 2007 include a $7.0 million non-cash impairment charge. | |
(4) | 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. |
125
Table of Contents
At December 31, | ||||||||
2007 | 2006 | |||||||
BALANCE SHEET DATA: | ||||||||
Current assets | $ | 112,352 | $ | 62,138 | ||||
Property, plant and equipment, net | 270,586 | 242,083 | ||||||
Other assets | 11,686 | 12,189 | ||||||
Total assets | $ | 394,624 | $ | 316,410 | ||||
Current liabilities | $ | 75,314 | $ | 30,686 | ||||
Other liabilities | 9,095 | 8,117 | ||||||
Combined equity | 310,215 | 277,607 | ||||||
Total liabilities and combined equity | $ | 394,624 | $ | 316,410 | ||||
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
INCOME STATEMENT DATA: | ||||||||||||
Revenues | $ | 220,381 | $ | 190,320 | $ | 207,775 | ||||||
Operating income (loss) | 41,147 | (26,885 | ) | 6,696 | ||||||||
Net income (loss) | 26,506 | (25,543 | ) | 6,509 |
126
Table of Contents
At December 31, | ||||||||
2007 | 2006 | |||||||
BALANCE SHEET DATA: | ||||||||
Current assets | $ | 83,962 | $ | 65,048 | ||||
Property, plant and equipment, net | 915,572 | 639,641 | ||||||
Other assets | 176,091 | 192,027 | ||||||
Total assets | $ | 1,175,625 | $ | 896,716 | ||||
Current liabilities | $ | 43,951 | $ | 49,708 | ||||
Other liabilities | 25,002 | 28,802 | ||||||
Combined equity | 1,106,672 | 818,206 | ||||||
Total liabilities and combined equity | $ | 1,175,625 | $ | 896,716 | ||||
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
INCOME STATEMENT DATA: | ||||||||||||
Revenues | $ | 477,077 | $ | 372,240 | $ | 347,561 | ||||||
Operating income | 98,549 | 48,387 | 9,142 | |||||||||
Net income | 93,491 | 40,608 | 4,668 |
127
Table of Contents
At December 31, | ||||||||
2007 | 2006 | |||||||
BALANCE SHEET DATA: | ||||||||
Current assets | $ | 46,795 | $ | 56,689 | ||||
Property, plant and equipment, net | 1,122,108 | 1,178,811 | ||||||
Other assets | 4,338 | 10,108 | ||||||
Total assets | $ | 1,173,241 | $ | 1,245,608 | ||||
Current liabilities | $ | 19,720 | $ | 22,043 | ||||
Other liabilities | �� | 96,791 | 510,773 | |||||
Combined equity | 1,056,730 | 712,792 | ||||||
Total liabilities and combined equity | $ | 1,173,241 | $ | 1,245,608 | ||||
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
| | | | | |||||||||||
INCOME STATEMENT DATA: | ||||||||||||
Revenues | $ | 156,780 | $ | 153,996 | $ | 154,297 | ||||||
Operating income | 85,550 | 71,977 | 78,027 | |||||||||
Net income | 53,590 | 42,732 | 29,086 |
128
Table of Contents
At December 31, | ||||||||
2007 | 2006 | |||||||
BALANCE SHEET DATA: | ||||||||
Current assets | $ | 3,187 | $ | 3,324 | ||||
Property, plant and equipment, net | 47,322 | 51,159 | ||||||
Total assets | $ | 50,509 | $ | 54,483 | ||||
Current liabilities | $ | 970 | $ | 832 | ||||
Other liabilities | 2 | 2 | ||||||
Combined equity | 49,537 | 53,649 | ||||||
Total liabilities and combined equity | $ | 50,509 | $ | 54,483 | ||||
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
| | | | | |||||||||||
INCOME STATEMENT DATA: | ||||||||||||
Revenues | $ | 19,844 | $ | 19,014 | $ | 16,849 | ||||||
Operating income | 5,961 | 4,626 | 2,606 | |||||||||
Net income | 6,029 | 4,729 | 2,650 |
129
Table of Contents
South Monco | ||||||||||||
Acquisition | Other | Total | ||||||||||
Assets acquired in business combination: | ||||||||||||
Property, plant and equipment, net | $ | 36,000 | $ | 8,386 | $ | 44,386 | ||||||
Intangible assets | — | (8,460 | ) | (8,460 | ) | |||||||
Total assets acquired | 36,000 | (74 | ) | 35,926 | ||||||||
Liabilities assumed in business combination: | ||||||||||||
Other long-term liabilities | (1,000 | ) | (244 | ) | (1,244 | ) | ||||||
Total liabilities assumed | (1,000 | ) | (244 | ) | (1,244 | ) | ||||||
Total assets acquired less liabilities assumed | 35,000 | (318 | ) | 34,682 | ||||||||
Total cash used for business combinations | 35,000 | 793 | 35,793 | |||||||||
Goodwill | $ | — | $ | 1,111 | $ | 1,111 | ||||||
Cash payment to Lewis | $ | 145,197 | ||
Fair value of our 7,115,844 common units issued to Lewis | 181,112 | |||
Total consideration | $ | 326,309 | ||
130
Table of Contents
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 | ||||
131
Table of Contents
At December 31, 2007 | At December 31, 2006 | |||||||||||||||||||||||
Gross | Accum. | Carrying | Gross | Accum. | Carrying | |||||||||||||||||||
Value | Amort. | Value | Value | Amort. | Value | |||||||||||||||||||
NGL Pipelines & Services: | ||||||||||||||||||||||||
Shell Processing Agreement | $ | 206,216 | $ | (78,252 | ) | $ | 127,964 | $ | 206,216 | $ | (67,204 | ) | $ | 139,012 | ||||||||||
Encinal gas processing customer relationship | 127,119 | (17,470 | ) | 109,649 | 127,119 | (6,049 | ) | 121,070 | ||||||||||||||||
STMA and GulfTerra NGL Business customer relationships | 49,784 | (17,537 | ) | 32,247 | 49,784 | (12,980 | ) | 36,804 | ||||||||||||||||
Pioneer gas processing contracts | 37,752 | (736 | ) | 37,016 | 37,752 | — | 37,752 | |||||||||||||||||
Markham NGL storage contracts | 32,664 | (14,154 | ) | 18,510 | 32,664 | (9,800 | ) | 22,864 | ||||||||||||||||
Toca-Western contracts | 31,229 | (8,718 | ) | 22,511 | 31,229 | (7,156 | ) | 24,073 | ||||||||||||||||
Piceance Creek customer relationship | — | — | — | 8,460 | — | 8,460 | ||||||||||||||||||
Other | 35,261 | (10,087 | ) | 25,174 | 35,370 | (7,455 | ) | 27,915 | ||||||||||||||||
Segment total | 520,025 | (146,954 | ) | 373,071 | 528,594 | (110,644 | ) | 417,950 | ||||||||||||||||
Onshore Natural Gas Pipelines & Services: | ||||||||||||||||||||||||
San Juan Gathering System customer relationships | 331,311 | (73,087 | ) | 258,224 | 331,311 | (52,318 | ) | 278,993 | ||||||||||||||||
Petal & Hattiesburg natural gas storage contracts | 100,499 | (27,931 | ) | 72,568 | 100,499 | (19,337 | ) | 81,162 | ||||||||||||||||
Other | 31,741 | (8,381 | ) | 23,360 | 31,741 | (5,747 | ) | 25,994 | ||||||||||||||||
Segment total | 463,551 | (109,399 | ) | 354,152 | 463,551 | (77,402 | ) | 386,149 | ||||||||||||||||
Offshore Pipelines & Services: | ||||||||||||||||||||||||
Offshore pipeline & platform customer relationships | 205,845 | (73,905 | ) | 131,940 | 205,845 | (54,636 | ) | 151,209 | ||||||||||||||||
Other | 1,167 | (49 | ) | 1,118 | 1,167 | — | 1,167 | |||||||||||||||||
Segment total | 207,012 | (73,954 | ) | 133,058 | 207,012 | (54,636 | ) | 152,376 | ||||||||||||||||
Petrochemical Services: | ||||||||||||||||||||||||
Mont Belvieu propylene fractionation contracts | 53,000 | (8,960 | ) | 44,040 | 53,000 | (7,445 | ) | 45,555 | ||||||||||||||||
Other | 14,906 | (2,227 | ) | 12,679 | 3,674 | (1,749 | ) | 1,925 | ||||||||||||||||
Segment total | 67,906 | (11,187 | ) | 56,719 | 56,674 | (9,194 | ) | 47,480 | ||||||||||||||||
Total all segments | $ | 1,258,494 | $ | (341,494 | ) | $ | 917,000 | $ | 1,255,831 | $ | (251,876 | ) | $ | 1,003,955 | ||||||||||
132
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
NGL Pipelines & Services | $ | 36,419 | $ | 31,159 | $ | 26,350 | ||||||
Onshore Natural Gas Pipelines & Services | 31,997 | 33,447 | 35,080 | |||||||||
Offshore Pipelines & Services | 19,318 | 22,156 | 25,515 | |||||||||
Petrochemical Services | 1,993 | 1,993 | 1,993 | |||||||||
Total all segments | $ | 89,727 | $ | 88,755 | $ | 88,938 | ||||||
133
Table of Contents
At December 31, | ||||||||
2007 | 2006 | |||||||
NGL Pipelines & Services | ||||||||
GulfTerra Merger | $ | 23,854 | $ | 23,854 | ||||
Acquisition of Indian Springs natural gas processing business | 13,162 | 13,162 | ||||||
Encinal acquisition | 95,280 | 95,166 | ||||||
Other | 21,410 | 20,413 | ||||||
Onshore Natural Gas Pipelines & Services | ||||||||
GulfTerra Merger | 279,956 | 279,956 | ||||||
Acquisition of Indian Springs natural gas gathering business | 2,165 | 2,165 | ||||||
Offshore Pipelines & Services | ||||||||
GulfTerra Merger | 82,135 | 82,135 | ||||||
Petrochemical Services | ||||||||
Acquisition of Mont Belvieu propylene fractionation business | 73,690 | 73,690 | ||||||
Total | $ | 591,652 | $ | 590,541 | ||||
134
Table of Contents
At December 31, | ||||||||
2007 | 2006 | |||||||
EPO senior debt obligations: | ||||||||
Multi-Year Revolving Credit Facility, variable rate, due November 2012 (1) | $ | 725,000 | $ | 410,000 | ||||
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 | ||||||
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 | ||||||
Senior Notes L, 6.30% fixed-rate, due September 2017 | 800,000 | — | ||||||
Petal GO Zone Bonds, variable rate, due August 2034 | 57,500 | — | ||||||
Duncan Energy Partners’ debt obligation: | ||||||||
$300 Million Revolving Credit Facility, variable rate, due February 2011 | 200,000 | — | ||||||
Dixie Revolving Credit Facility, variable rate, due June 2010 | 10,000 | 10,000 | ||||||
Other, 8.75% fixed-rate, due June 2010 (3) | — | 5,068 | ||||||
Total principal amount of senior debt obligations | 5,646,500 | 4,779,068 | ||||||
EPO Junior Subordinated Notes A, due August 2066 | 550,000 | 550,000 | ||||||
EPO Junior Subordinated Notes B, due January 2068 | 700,000 | — | ||||||
Total principal amount of senior and junior debt obligations | 6,896,500 | 5,329,068 | ||||||
Other, including unamortized discounts and premiums and changes in fair value (4) | 9,645 | (33,478 | ) | |||||
Long-term debt | $ | 6,906,145 | $ | 5,295,590 | ||||
Standby letters of credit outstanding | $ | 1,100 | $ | 49,858 | ||||
(1) | In November 2007, EPO executed an amended and restated revolving credit agreement governing its Multi-Year Revolving Credit Facility. This new credit agreement increases the capacity from $1.25 billion to $1.75 billion and extends the maturity date of amounts borrowed under EPO’s Multi-Year Revolving Credit Facility from October 2011 to November 2012. | |
(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, EPO repaid this note in October 2007, using cash and available credit capacity under its then $1.25 billion Multi-Year Revolving Credit Facility. | |
(3) | Represents remaining debt obligations assumed in connection with the GulfTerra Merger, which were redeemed in the fourth quarter of 2007. | |
(4) | The December 31, 2007 amount includes an asset of $14.8 million related to fair value hedges offset by a net $5.2 million in unamortized discounts. The December 31, 2006 amount includes a liability of $29.1 million related to fair value hedges and a net $4.4 million in unamortized discounts. |
135
Table of Contents
136
Table of Contents
137
Table of Contents
138
Table of Contents
139
Table of Contents
Range of | Weighted-average | |||||
interest rates | interest rate | |||||
paid | paid | |||||
EPO’s Multi-Year Revolving Credit Facility | 5.10% to 8.25% | 5.78 | % | |||
Duncan Energy Partners’ Revolving Credit Facility | 5.52% to 6.42% | 6.23 | % | |||
Dixie Revolving Credit Facility | 5.50% to 5.67% | 5.63 | % | |||
Canadian Enterprise Revolving Credit Facility | 5.01% to 5.82% | 5.68 | % | |||
Petal GO Zone Bonds | 3.11% to 4.15% | 3.56 | % |
2008 | $ | — | ||
2009 | 500,000 | |||
2010 | 591,840 | |||
2011 | 650,000 | |||
2012 | 697,160 | |||
Thereafter | 4,457,500 | |||
Total scheduled principal payments | $ | 6,896,500 | ||
140
Table of Contents
Our | Scheduled Maturities of Debt | ||||||||||||||||||||||||||||||||
Ownership | After | ||||||||||||||||||||||||||||||||
Interest | Total | 2008 | 2009 | 2010 | 2011 | 2012 | 2012 | ||||||||||||||||||||||||||
Poseidon | 36 | % | $ | 91,000 | $ | — | $ | — | $ | — | $ | 91,000 | $ | — | $ | — | |||||||||||||||||
Evangeline | 49.5 | % | 20,650 | 5,000 | 5,000 | 10,650 | — | — | — | ||||||||||||||||||||||||
Total | $ | 111,650 | $ | 5,000 | $ | 5,000 | $ | 10,650 | $ | 91,000 | $ | — | $ | — | |||||||||||||||||||
141
Table of Contents
142
Table of Contents
Net Proceeds from Sale of Common Units | ||||||||||||||||
Number of | Contributed | Contributed by | Total | |||||||||||||
common units | by Limited | General | Net | |||||||||||||
issued | Partners | Partner | Proceeds | |||||||||||||
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 | |||||||||
Fiscal 2007: | ||||||||||||||||
Other offerings, primarily DRIP | 2,056,615 | $ | 60,445 | $ | 1,232 | $ | 61,677 | |||||||||
Total 2007 | 2,056,615 | $ | 60,445 | $ | 1,232 | $ | 61,677 | |||||||||
Restricted | ||||||||||||
Common | Common | Treasury | ||||||||||
Units | Units | Units | ||||||||||
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 | — | |||||||||
Units issued in connection with other offerings | 2,056,615 | — | — | |||||||||
Units issued in connection with equity-based awards | 244,071 | 738,040 | — | |||||||||
Forfeiture or settlement of restricted units | — | (149,853 | ) | — | ||||||||
Conversion of restricted units to common units | 4,884 | (4,884 | ) | — | ||||||||
Balance, December 31, 2007 | 433,608,763 | 1,688,540 | — | |||||||||
143
Table of Contents
Restricted | ||||||||||||
Common | Common | |||||||||||
units | units | Total | ||||||||||
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 | |||||||||
Net income | 416,323 | 1,405 | 417,728 | |||||||||
Operating leases paid by EPCO | 2,056 | 7 | 2,063 | |||||||||
Cash distributions to partners | (831,155 | ) | (2,638 | ) | (833,793 | ) | ||||||
Unit option reimbursements to EPCO | (2,999 | ) | — | (2,999 | ) | |||||||
Net proceeds from sales of common units | 60,445 | — | 60,445 | |||||||||
Proceeds from exercise of unit options | 7,549 | — | 7,549 | |||||||||
Repurchase of restricted units and options | (512 | ) | (1,056 | ) | (1,568 | ) | ||||||
Amortization of equity-based awards | 4,663 | 8,890 | 13,553 | |||||||||
Balance, December 31, 2007 | $ | 5,976,947 | $ | 15,948 | $ | 5,992,895 | ||||||
144
Table of Contents
§ | 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 | Date | Date | ||||||||||
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 | ||||||||
2007 | ||||||||||||
1st Quarter | $ | 0.4750 | Apr. 30, 2007 | May 10, 2007 | ||||||||
2nd Quarter | $ | 0.4825 | Jul. 31, 2007 | Aug. 9, 2007 | ||||||||
3rd Quarter | $ | 0.4900 | Oct. 31, 2007 | Nov. 8, 2007 | ||||||||
4th Quarter | $ | 0.5000 | Jan. 31, 2008 | Feb. 7, 2008 |
At December 31, | |||||||||
2007 | 2006 | ||||||||
Commodity financial instruments (1) | $ | (21,619 | ) | $ | (3,622 | ) | |||
Interest rate financial instruments (1) | 34,980 | 26,034 | |||||||
Foreign currency hedges (1) | 1,308 | — | |||||||
Foreign currency translation adjustment (1) | 1,200 | (807 | ) | ||||||
Pension and postretirement benefit plans (2) | 588 | (464 | ) | ||||||
Total accumulated other comprehensive income | $ | 16,457 | $ | 21,141 | |||||
(1) | See Note 2 for additional information regarding these components of accumulated other comprehensive income. | |
(2) | See Note 6 for additional information regarding pension and postretirement benefit plans. |
145
Table of Contents
146
Table of Contents
For the Year Ended December 31, | ||||||||||||||
2007 | 2006 | 2005 | ||||||||||||
Revenues (1) | $ | 16,950,125 | $ | 13,990,969 | $ | 12,256,959 | ||||||||
Less: | Operating costs and expenses (1) | (16,009,051 | ) | (13,089,091 | ) | (11,546,225 | ) | |||||||
Add: | Equity in income of unconsolidated affiliates (1) | 29,658 | 21,565 | 14,548 | ||||||||||
Depreciation, amortization and accretion in operating costs and expenses (2) | 513,840 | 440,256 | 413,441 | |||||||||||
Operating lease expenses paid by EPCO (2) | 2,105 | 2,109 | 2,112 | |||||||||||
Loss (gain) on sale of assets in operating costs and expenses (2) | 5,391 | (3,359 | ) | (4,488 | ) | |||||||||
Total segment gross operating margin | $ | 1,492,068 | $ | 1,362,449 | $ | 1,136,347 | ||||||||
(1) | These amounts are taken from our Statements of Consolidated Operations. | |
(2) | These non-cash expenses are taken from the operating activities section of our Statements of Consolidated Cash Flows. |
For the Year Ended December 31, | ||||||||||||||||
2007 | 2006 | 2005 | ||||||||||||||
Total segment gross operating margin | $ | 1,492,068 | $ | 1,362,449 | $ | 1,136,347 | ||||||||||
Adjustments to reconcile total segment gross operating margin to operating income: | ||||||||||||||||
Depreciation, amortization and accretion in operating costs and expenses | (513,840 | ) | (440,256 | ) | (413,441 | ) | ||||||||||
Operating lease expense paid by EPCO | (2,105 | ) | (2,109 | ) | (2,112 | ) | ||||||||||
Gain (loss) on sale of assets in operating costs and expenses | (5,391 | ) | 3,359 | 4,488 | ||||||||||||
General and administrative costs | (87,695 | ) | (63,391 | ) | (62,266 | ) | ||||||||||
Consolidated operating income | 883,037 | 860,052 | 663,016 | |||||||||||||
Other expense, net | (303,463 | ) | (229,967 | ) | (225,178 | ) | ||||||||||
Income before provision for income taxes, minority interest and cumulative effect of change in accounting principle | $ | 579,574 | $ | 630,085 | $ | 437,838 | ||||||||||
147
Table of Contents
Reportable Segments | ||||||||||||||||||||||||
Onshore | ||||||||||||||||||||||||
NGL | Natural Gas | Offshore | Adjustments | |||||||||||||||||||||
Pipelines | Pipelines | Pipelines | Petrochemical | and | Consolidated | |||||||||||||||||||
& Services | & Services | & Services | Services | Eliminations | Totals | |||||||||||||||||||
Revenues from third parties: | ||||||||||||||||||||||||
Year ended December 31, 2007 | $ | 12,101,715 | $ | 1,788,219 | $ | 222,642 | $ | 2,184,833 | $ | — | $ | 16,297,409 | ||||||||||||
Year ended December 31, 2006 | 10,079,534 | 1,407,872 | 144,065 | 1,956,268 | — | 13,587,739 | ||||||||||||||||||
Year ended December 31, 2005 | 9,006,730 | 1,185,577 | 110,100 | 1,587,037 | — | 11,889,444 | ||||||||||||||||||
Revenues from related parties: | ||||||||||||||||||||||||
Year ended December 31, 2007 | 369,654 | 281,876 | 1,169 | 17 | — | 652,716 | ||||||||||||||||||
Year ended December 31, 2006 | 110,409 | 291,023 | 1,798 | — | — | 403,230 | ||||||||||||||||||
Year ended December 31, 2005 | 16,689 | 350,025 | 696 | 105 | — | 367,515 | ||||||||||||||||||
Intersegment and intrasegment revenues: | ||||||||||||||||||||||||
Year ended December 31, 2007 | 5,346,571 | 191,741 | 1,959 | 514,852 | (6,055,123 | ) | — | |||||||||||||||||
Year ended December 31, 2006 | 4,131,776 | 113,132 | 1,679 | 383,754 | (4,630,341 | ) | — | |||||||||||||||||
Year ended December 31, 2005 | 3,334,763 | 41,576 | 1,353 | 346,458 | (3,724,150 | ) | — | |||||||||||||||||
Total revenues: | ||||||||||||||||||||||||
Year ended December 31, 2007 | 17,817,940 | 2,261,836 | 225,770 | 2,699,702 | (6,055,123 | ) | 16,950,125 | |||||||||||||||||
Year ended December 31, 2006 | 14,321,719 | 1,812,027 | 147,542 | 2,340,022 | (4,630,341 | ) | 13,990,969 | |||||||||||||||||
Year ended December 31, 2005 | 12,358,182 | 1,577,178 | 112,149 | 1,933,600 | (3,724,150 | ) | 12,256,959 | |||||||||||||||||
Equity in income of unconsolidated affiliates: | ||||||||||||||||||||||||
Year ended December 31, 2007 | 6,031 | 9,540 | 12,628 | 1,459 | — | 29,658 | ||||||||||||||||||
Year ended December 31, 2006 | 5,715 | 2,872 | 11,909 | 1,069 | — | 21,565 | ||||||||||||||||||
Year ended December 31, 2005 | 5,553 | 2,384 | 6,125 | 486 | — | 14,548 | ||||||||||||||||||
Gross operating margin by individual business segment and in total: | ||||||||||||||||||||||||
Year ended December 31, 2007 | 812,521 | 335,683 | 171,551 | 172,313 | — | 1,492,068 | ||||||||||||||||||
Year ended December 31, 2006 | 752,548 | 333,399 | 103,407 | 173,095 | — | 1,362,449 | ||||||||||||||||||
Year ended December 31, 2005 | 579,706 | 353,076 | 77,505 | 126,060 | — | 1,136,347 | ||||||||||||||||||
Segment assets: | ||||||||||||||||||||||||
At December 31, 2007 | 4,570,555 | 3,702,297 | 1,452,568 | 687,856 | 1,173,988 | 11,587,264 | ||||||||||||||||||
At December 31, 2006 | 3,249,486 | 3,611,974 | 734,659 | 502,345 | 1,734,083 | 9,832,547 | ||||||||||||||||||
Investments in and advances to unconsolidated affiliates (see Note 11): | ||||||||||||||||||||||||
At December 31, 2007 | 117,089 | 239,327 | 484,588 | 17,335 | — | 858,339 | ||||||||||||||||||
At December 31, 2006 | 111,229 | 124,591 | 310,136 | 18,603 | — | 564,559 | ||||||||||||||||||
Intangible Assets (see Note 13): | ||||||||||||||||||||||||
At December 31, 2007 | 373,071 | 354,152 | 133,058 | 56,719 | — | 917,000 | ||||||||||||||||||
At December 31, 2006 | 417,950 | 386,149 | 152,376 | 47,480 | — | 1,003,955 | ||||||||||||||||||
Goodwill (see Note 13): | ||||||||||||||||||||||||
At December 31, 2007 | 153,706 | 282,121 | 82,135 | 73,690 | — | 591,652 | ||||||||||||||||||
At December 31, 2006 | 152,595 | 282,121 | 82,135 | 73,690 | — | 590,541 |
148
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Revenues from consolidated operations | ||||||||||||
EPCO and affiliates | $ | 362,076 | $ | 98,671 | $ | 311 | ||||||
Unconsolidated affiliates | 290,640 | 304,559 | 367,204 | |||||||||
Total | $ | 652,716 | $ | 403,230 | $ | 367,515 | ||||||
Operating costs and expenses | ||||||||||||
EPCO and affiliates | $ | 329,699 | $ | 311,537 | $ | 293,134 | ||||||
Unconsolidated affiliates | 32,765 | 31,606 | 23,563 | |||||||||
Total | $ | 362,464 | $ | 343,143 | $ | 316,697 | ||||||
General and administrative expenses | ||||||||||||
EPCO and affiliates | $ | 56,518 | $ | 41,265 | $ | 40,954 | ||||||
§ | EPCO and its private company subsidiaries; | ||
§ | EPGP, our sole general partner; | ||
§ | Enterprise GP Holdings, which owns and controls our general partner; | ||
§ | TEPPCO, which is owned and controlled by Enterprise GP Holdings; | ||
§ | the Employee Partnerships (see Note 5); and | ||
§ | Energy Transfer Equity, an equity method investment of Enterprise GP Holdings. |
149
Table of Contents
§ | EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel 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. |
150
Table of Contents
§ | If a business opportunity to acquire “equity securities” (as defined below) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), 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) 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. |
151
Table of Contents
acquisition. Enterprise Products Partners will be presumed to want to acquire the equity securities until such time as EPGP advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing EPGP’s Chief Executive Officer and ACG Committee. | |||
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition. | |||
In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to TEPPCO (including 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 Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy Partners (including DEP GP), Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan Energy Partners. It will be presumed that Enterprise Products Partners will pursue the business opportunity until such time as its general partner advises the EPCO Group, EPE Holdings and DEP GP that it has 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 EPGP after consultation with and subject to the approval of the ACG Committee of EPGP. If the purchase price or cost is reasonably likely to be less than $100 million, the Chief Executive Officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee. | |||
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition. | |||
In the event that Enterprise Products Partners abandons the business opportunity for itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity. It will be presumed that Enterprise GP Holdings will pursue such acquisition until such time as its general partner declines such opportunity (in accordance with the procedures described above for Enterprise Products Partners) and advises the EPCO Group that it has abandoned the pursuit of such business opportunity. Should this occur, the EPCO Group may either pursue the business opportunity or offer the business opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates. |
152
Table of Contents
153
Table of Contents
§ | 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 $268.0 million, $277.7 million and $331.5 million for the years ended December 31, 2007, 2006 and 2005. In addition, we furnished $1.1 million in letters of credit on behalf of Evangeline at December 31, 2007. |
154
Table of Contents
§ | 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 $30.4 million, $34.9 million and $26.0 million for the years ended December 31, 2007, 2006 and 2005. Revenues from Promix were $17.3 million, $21.8 million and $25.8 million for the years ended December 31, 2007, 2006 and 2005. | ||
§ | We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $9.3 million, $8.9 million and $8.3 million for the years ended December 31, 2007, 2006 and 2005. |
155
Table of Contents
§ | indemnification for certain environmental liabilities, tax liabilities and right-of-way defects; | ||
§ | reimbursement of certain expenditures incurred by DEP South Texas NGL and Mont Belvieu Caverns; | ||
§ | a right of first refusal to EPO in Duncan Energy Partners’ current and future subsidiaries 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 in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct its business that arise through February 5, 2010; and | ||
§ | certain income tax liabilities attributable to the operation of the assets contributed to Duncan Energy Partners in connection with its initial public offering prior to February 5, 2007. |
156
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Current: | ||||||||||||
Federal | $ | 4,828 | $ | 7,694 | $ | 1,105 | ||||||
State | 3,871 | 1,148 | 301 | |||||||||
Total current | 8,699 | 8,842 | 1,406 | |||||||||
Deferred: | ||||||||||||
Federal | 2,784 | 6,109 | 5,968 | |||||||||
State | 3,774 | 6,372 | 988 | |||||||||
Total deferred | 6,558 | 12,481 | 6,956 | |||||||||
Total provision for income taxes | $ | 15,257 | $ | 21,323 | $ | 8,362 | ||||||
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Pre Tax Net Book Income (“NBI”) | $ | 579,574 | $ | 630,085 | $ | 437,838 | ||||||
Revised Texas franchise tax | 7,146 | 8,119 | — | |||||||||
State income taxes (net of federal benefit) | 325 | (396 | ) | 838 | ||||||||
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities | 5,318 | 13,347 | 7,656 | |||||||||
Taxes charged to cumulative effect of changes in accounting principle | — | (3 | ) | 65 | ||||||||
Valuation allowance | 2,347 | 123 | — | |||||||||
Other permanent differences | 121 | 133 | (197 | ) | ||||||||
Provision for income taxes | 15,257 | $ | 21,323 | $ | 8,362 | |||||||
Effective income tax rate | 2.6 | % | 3.4 | % | 1.9 | % | ||||||
157
Table of Contents
At December 31, | ||||||||
2007 | 2006 | |||||||
Deferred Tax Assets: | ||||||||
Net operating loss carryovers | $ | 23,270 | $ | 19,175 | ||||
Credit carryover | 26 | 26 | ||||||
Charitable contribution carryover | 16 | 12 | ||||||
Employee benefit plans | 3,214 | 1,990 | ||||||
Deferred revenue | 642 | 328 | ||||||
Reserve for legal fees and damages | 478 | — | ||||||
Equity investment in partnerships | 409 | 223 | ||||||
Asset retirement obligation | 80 | 43 | ||||||
Accruals | 1,068 | 709 | ||||||
Total Deferred Tax Assets | 29,203 | 22,506 | ||||||
Valuation allowance | (5,345 | ) | (2,994 | ) | ||||
Net Deferred Tax Assets | 23,858 | 19,512 | ||||||
Deferred Tax Liabilities: | ||||||||
Property, plant and equipment | 40,520 | 30,604 | ||||||
Other | 99 | 78 | ||||||
Total Deferred Tax Liabilities | 40,619 | 30,682 | ||||||
Total Net Deferred Tax Liabilities | $ | (16,761 | ) | $ | (11,170 | ) | ||
Current portion of total net deferred tax assets | $ | 1,081 | $ | 698 | ||||
Long-term portion of total net deferred tax liabilities | $ | (17,842 | ) | $ | (11,868 | ) | ||
158
Table of Contents
For The Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Net income | $ | 533,674 | $ | 601,155 | $ | 419,508 | ||||||
Less incentive earnings allocations to EPGP | (107,421 | ) | (86,710 | ) | (63,884 | ) | ||||||
Net income available after incentive earnings allocation | 426,253 | 514,445 | 355,624 | |||||||||
Multiplied by EPGP ownership interest | 2.0 | % | 2.0 | % | 2.0 | % | ||||||
Standard earnings allocation to EPGP | $ | 8,525 | $ | 10,289 | $ | 7,112 | ||||||
Incentive earnings allocation to EPGP | $ | 107,421 | $ | 86,710 | $ | 63,884 | ||||||
Standard earnings allocation to EPGP | 8,525 | 10,289 | 7,112 | |||||||||
EPGP interest in net income | $ | 115,946 | $ | 96,999 | $ | 70,996 | ||||||
159
Table of Contents
For The Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Income before change in accounting principle and EPGP interest | $ | 533,674 | $ | 599,683 | $ | 423,716 | ||||||
Cumulative effect of change in accounting principle | — | 1,472 | (4,208 | ) | ||||||||
Net income | 533,674 | 601,155 | 419,508 | |||||||||
EPGP interest in net income | (115,946 | ) | (96,999 | ) | (70,996 | ) | ||||||
Net income available to limited partners | $ | 417,728 | $ | 504,156 | $ | 348,512 | ||||||
BASIC EARNINGS PER UNIT | ||||||||||||
Numerator | ||||||||||||
Income before change in accounting principle and EPGP interest | $ | 533,674 | $ | 599,683 | $ | 423,716 | ||||||
Cumulative effect of change in accounting principle | — | 1,472 | (4,208 | ) | ||||||||
EPGP interest in net income | (115,946 | ) | (96,999 | ) | (70,996 | ) | ||||||
Limited partners’ interest in net income | $ | 417,728 | $ | 504,156 | $ | 348,512 | ||||||
Denominator | ||||||||||||
Common units | 432,513 | 413,472 | 413,472 | |||||||||
Time-vested restricted units | 1,446 | 970 | 970 | |||||||||
Total | 433,959 | 414,442 | 414,442 | |||||||||
Basic earnings per unit | ||||||||||||
Income per unit before change in accounting principle and EPGP interest | $ | 1.23 | $ | 1.45 | $ | 1.11 | ||||||
Cumulative effect of change in accounting principle | — | — | (0.01 | ) | ||||||||
EPGP interest in net income | (0.27 | ) | (0.23 | ) | (0.19 | ) | ||||||
Limited partners’ interest in net income | $ | 0.96 | $ | 1.22 | $ | 0.91 | ||||||
DILUTED EARNINGS PER UNIT | ||||||||||||
Numerator | ||||||||||||
Income before change in accounting principle and EPGP interest | $ | 533,674 | $ | 599,683 | $ | 423,716 | ||||||
Cumulative effect of change in accounting principle | — | 1,472 | (4,208 | ) | ||||||||
EPGP interest in net income | (115,946 | ) | (96,999 | ) | (70,996 | ) | ||||||
Limited partners’ interest in net income | $ | 417,728 | $ | 504,156 | $ | 348,512 | ||||||
Denominator | ||||||||||||
Common units | 432,513 | 413,472 | 381,857 | |||||||||
Time-vested restricted units | 1,446 | 970 | 606 | |||||||||
Performance-based restricted units | 9 | 20 | 45 | |||||||||
Incremental option units | 459 | 297 | 455 | |||||||||
Total | 434,427 | 414,759 | 382,963 | |||||||||
Diluted earnings per unit | ||||||||||||
Income per unit before change in accounting principle and EPGP interest | $ | 1.23 | $ | 1.45 | $ | 1.11 | ||||||
Cumulative effect of change in accounting principle | — | — | (0.01 | ) | ||||||||
EPGP interest in net income | (0.27 | ) | (0.23 | ) | (0.19 | ) | ||||||
Limited partners’ interest in net income | $ | 0.96 | $ | 1.22 | $ | 0.91 | ||||||
160
Table of Contents
161
Table of Contents
Payment or Settlement due by Period | ||||||||||||||||||||||||||||
Contractual Obligations | Total | 2008 | 2009 | 2010 | 2011 | 2012 | Thereafter | |||||||||||||||||||||
Scheduled maturities of long-term debt | $ | 6,896,500 | $ | — | $ | 500,000 | $ | 591,840 | $ | 650,000 | $ | 697,160 | $ | 4,457,500 | ||||||||||||||
Operating lease obligations | $ | 325,705 | $ | 27,785 | $ | 25,866 | $ | 23,306 | $ | 23,785 | $ | 23,137 | $ | 201,826 | ||||||||||||||
Purchase obligations: | ||||||||||||||||||||||||||||
Product purchase commitments: | ||||||||||||||||||||||||||||
Estimated payment obligations: | ||||||||||||||||||||||||||||
Natural gas | $ | 685,600 | $ | 137,345 | $ | 136,970 | $ | 136,970 | $ | 136,970 | $ | 137,345 | $ | — | ||||||||||||||
NGLs | $ | 4,041,275 | $ | 697,277 | $ | 415,132 | $ | 415,132 | $ | 415,132 | $ | 415,132 | $ | 1,683,470 | ||||||||||||||
Petrochemicals | $ | 4,065,675 | $ | 1,751,152 | $ | 746,916 | $ | 514,155 | $ | 233,745 | $ | 141,623 | $ | 678,084 | ||||||||||||||
Other | $ | 60,385 | $ | 31,392 | $ | 14,962 | $ | 2,152 | $ | 2,051 | $ | 1,780 | $ | 8,048 | ||||||||||||||
Underlying major volume commitments: | ||||||||||||||||||||||||||||
Natural gas (in BBtus) | 91,350 | 18,300 | 18,250 | 18,250 | 18,250 | 18,300 | — | |||||||||||||||||||||
NGLs (in MBbls) | 50,798 | 9,745 | 5,086 | 5,086 | 5,086 | 5,086 | 20,709 | |||||||||||||||||||||
Petrochemicals (in MBbls) | 45,207 | 20,115 | 8,100 | 5,604 | 2,541 | 1,556 | 7,291 | |||||||||||||||||||||
Service payment commitments | $ | 8,962 | $ | 6,745 | $ | 1,564 | $ | 93 | $ | 93 | $ | 93 | $ | 374 | ||||||||||||||
Capital expenditure commitments | $ | 569,654 | $ | 569,654 | $ | — | $ | — | $ | — | $ | — | $ | — |
162
Table of Contents
§ | 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, 2007 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. At December 31, 2007, 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. |
163
Table of Contents
164
Table of Contents
165
Table of Contents
For the Year Ended December 31, | ||||||||
2007 | 2006 | |||||||
Business interruption proceeds: | ||||||||
Hurricane Ivan | $ | 377 | $ | 17,382 | ||||
Hurricane Katrina | 19,005 | 24,500 | ||||||
Hurricane Rita | 14,955 | 22,000 | ||||||
Other | 996 | — | ||||||
Total proceeds | 35,333 | 63,882 | ||||||
Property damage proceeds: | ||||||||
Hurricane Ivan | 1,273 | 24,104 | ||||||
Hurricane Katrina | 79,651 | 7,500 | ||||||
Hurricane Rita | 24,105 | 3,000 | ||||||
Other | 184 | — | ||||||
Total proceeds | 105,213 | 34,604 | ||||||
Total | $ | 140,546 | $ | 98,486 | ||||
166
Table of Contents
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Decrease (increase) in: | ||||||||||||
Accounts and notes receivable | $ | (703,346 | ) | $ | 155,628 | $ | (363,857 | ) | ||||
Inventories | (14,051 | ) | (66,288 | ) | (148,846 | ) | ||||||
Prepaid and other current assets | 41,266 | 14,261 | (51,163 | ) | ||||||||
Other assets | 5,630 | (22,581 | ) | 58,762 | ||||||||
Increase (decrease) in: | ||||||||||||
Accounts payable | 53,981 | (12,278 | ) | 45,802 | ||||||||
Accrued product payables | 862,941 | (8,344 | ) | 349,979 | ||||||||
Accrued expenses | 120,054 | (62,963 | ) | (161,989 | ) | |||||||
Accrued interest | 40,107 | 19,671 | 858 | |||||||||
Other current liabilities | 37,248 | 74,206 | 2,274 | |||||||||
Other liabilities | (2,524 | ) | (7,894 | ) | 1,785 | |||||||
Net effect of changes in operating accounts | $ | 441,306 | $ | 83,418 | $ | (266,395 | ) | |||||
Cash payments for interest, net of $75,476, $55,660 and $22,046 capitalized in 2007, 2006 and 2005, respectively | $ | 325,339 | $ | 213,365 | $ | 239,088 | ||||||
Cash payments for federal and state income taxes | $ | 5,760 | $ | 10,497 | $ | 5,160 | ||||||
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Assets acquired | $ | 37,037 | $ | 477,015 | $ | 353,176 | ||||||
Less liabilities assumed | (1,244 | ) | (19,403 | ) | (23,940 | ) | ||||||
Net assets acquired | 35,793 | 457,612 | 329,236 | |||||||||
Less equity issued | — | (181,112 | ) | — | ||||||||
Less cash acquired | — | — | (2,634 | ) | ||||||||
Cash used for business combinations, net of cash received | $ | 35,793 | $ | 276,500 | $ | 326,602 | ||||||
167
Table of Contents
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
For the Year Ended December 31, 2007: | ||||||||||||||||
Revenues | $ | 3,322,854 | $ | 4,212,806 | $ | 4,111,996 | $ | 5,302,469 | ||||||||
Operating income | 187,924 | 214,562 | 210,830 | 269,721 | ||||||||||||
Income before change in accounting principle | 112,045 | 142,154 | 117,606 | 161,869 | ||||||||||||
Net income | 112,045 | 142,154 | 117,606 | 161,869 | ||||||||||||
Income per unit before change in accounting principle: | ||||||||||||||||
Basic | $ | 0.20 | $ | 0.26 | $ | 0.20 | $ | 0.30 | ||||||||
Diluted | $ | 0.20 | $ | 0.26 | $ | 0.20 | $ | 0.30 | ||||||||
Net income per unit: | ||||||||||||||||
Basic | $ | 0.20 | $ | 0.26 | $ | 0.20 | $ | 0.30 | ||||||||
Diluted | $ | 0.20 | $ | 0.26 | $ | 0.20 | $ | 0.30 | ||||||||
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 change in accounting principle | 132,302 | 126,295 | 208,302 | 132,784 | ||||||||||||
Net income | 133,777 | 126,295 | 208,302 | 132,781 | ||||||||||||
Income per unit before change in accounting principle: | ||||||||||||||||
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 |
168
Table of Contents
At December 31, | ||||||||
2007 | 2006 | |||||||
ASSETS | ||||||||
Current assets | $ | 2,544,973 | $ | 1,915,937 | ||||
Property, plant and equipment, net | 11,587,264 | 9,832,547 | ||||||
Investments in and advances to unconsolidated affiliates, net | 858,339 | 564,559 | ||||||
Intangible assets, net | 917,000 | 1,003,955 | ||||||
Goodwill | 591,652 | 590,541 | ||||||
Deferred tax asset | 3,113 | 1,632 | ||||||
Other assets | 112,345 | 74,103 | ||||||
Total | $ | 16,614,686 | $ | 13,983,274 | ||||
LIABILITIES AND PARTNERS’ EQUITY | ||||||||
Current liabilities | $ | 3,044,002 | $ | 1,986,444 | ||||
Long-term debt | 6,906,145 | 5,295,590 | ||||||
Other long-term liabilities | 95,112 | 99,845 | ||||||
Minority interest | 439,854 | 136,249 | ||||||
Partners’ equity | 6,129,573 | 6,465,146 | ||||||
Total | $ | 16,614,686 | $ | 13,983,274 | ||||
Total EPO debt obligations guaranteed by us | $ | 6,686,500 | $ | 5,314,000 | ||||
For the Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
Revenues | $ | 16,950,125 | $ | 13,990,969 | $ | 12,256,959 | ||||||
Costs and expenses | 16,094,248 | 13,148,530 | 11,605,923 | |||||||||
Equity in income of unconsolidated affiliates | 29,658 | 21,565 | 14,548 | |||||||||
Operating income | 885,535 | 864,004 | 665,584 | |||||||||
Other expense | (305,236 | ) | (231,876 | ) | (226,075 | ) | ||||||
Income before provision for income taxes, minority interest and change in accounting principle | 580,299 | 632,128 | 439,509 | |||||||||
Provision for income taxes | (15,317 | ) | (21,198 | ) | (8,362 | ) | ||||||
Income before minority interest and change in accounting principle | 564,982 | 610,930 | 431,147 | |||||||||
Minority interest | (30,737 | ) | (9,190 | ) | (5,989 | ) | ||||||
Income before change in accounting principle | 534,245 | 601,740 | 425,158 | |||||||||
Cumulative effect of change in accounting principle | — | 1,472 | (4,208 | ) | ||||||||
Net income | $ | 534,245 | $ | 603,212 | $ | 420,950 | ||||||
169
Table of Contents
§ | Distributions of cash flow-Each quarter, 100% of the cash distributions received by Enterprise LP from Enterprise GP Holdings and us will be distributed to the Class A limited partner until EPCO Holdings has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by Enterprise LP will be distributed to the Class B limited partners. The Class A preferred return equals the Class A capital base (as defined below) multiplied by 5.0% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to Enterprise LP, plus any unpaid Class A preferred return from prior periods, less any distributions made by Enterprise LP of proceeds from the sale of units owned by Enterprise LP (as described below). | ||
§ | Liquidating Distributions-Upon liquidation of Enterprise LP, units having a fair market value equal to the Class A limited partner capital base will be distributed to EPCO Holdings, 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 Enterprise LP sells any units that it beneficially 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. |
170
Table of Contents
(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. |
171
Table of Contents
172
Table of Contents
OVER FINANCIAL REPORTING AS OF DECEMBER 31, 2007
/s/ Michael A. Creel | /s/ W. Randall Fowler | |||||||||
Name: | Michael A. Creel | Name: | W. Randall Fowler | |||||||
Title: | Chief Executive Officer of our general partner, Enterprise Products GP, LLC | Title: | Chief Financial Officer of our general partner, Enterprise Products GP, LLC |
173
Table of Contents
Unitholders of Enterprise Products Partners L.P.
Houston, Texas
174
Table of Contents
February 28, 2008
175
Table of Contents
176
Table of Contents
serve on its ACG Committee. The members of the ACG Committee are independent directors, free from any relationship with us or any of our subsidiaries that would interfere with the exercise of independent judgment. |
§ | review potential conflicts of interest, including related party transactions; | ||
§ | monitoring the integrity of our financial reporting process and related systems of internal control; | ||
§ | ensuring our legal and regulatory compliance and that of EPGP; | ||
§ | overseeing the independence and performance of our independent public accountant; | ||
§ | approving all services performed by our independent public accountant; | ||
§ | providing for an avenue of communication among the independent public accountant, 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 long-term incentive plans. |
177
Table of Contents
Name | Age | Position with EPGP | ||||
Dan L. Duncan (1) | 75 | Director and Chairman | ||||
Michael A. Creel (1) | 54 | Director, President and Chief Executive Officer | ||||
W. Randall Fowler (1) | 51 | Director, Executive Vice President and Chief Financial Officer | ||||
Richard H. Bachmann (1) | 55 | Director, Executive Vice President, Chief Legal Officer and Secretary | ||||
Dr. Ralph S. Cunningham | 67 | Director | ||||
E. William Barnett (2,3) | 75 | Director | ||||
Rex C. Ross (2) | 64 | Director | ||||
Charles M. Rampacek (2) | 64 | Director | ||||
William Ordemann (1) | 48 | Executive Vice President and Chief Operating Officer | ||||
James H. Lytal (1) | 50 | Executive Vice President | ||||
A.J. Teague (1) | 62 | Executive Vice President | ||||
Gil H. Radtke | 46 | Senior Vice President | ||||
James M. Collingsworth | 53 | Senior Vice President | ||||
Michael J. Knesek (1) | 53 | Senior Vice President, Controller and Principal Accounting Officer |
(1) | Executive officer | |
(2) | Member of ACG Committee | |
(3) | Chairman of ACG Committee |
178
Table of Contents
179
Table of Contents
180
Table of Contents
181
Table of Contents
Name and | Unit | Option | All Other | |||||||||||||||||||||||||
Principal | Salary | Bonus | Awards | Awards | Compensation | Total | ||||||||||||||||||||||
Position | Year | ($) | ($) (5) | ($) (6) | ($) (7) | ($) (8) | ($) | |||||||||||||||||||||
Michael A. Creel (1) | 2007 | $ | 361,808 | $ | 365,370 | $ | 517,707 | $ | 44,449 | $ | 108,017 | $ | 1,397,351 | |||||||||||||||
2006 | 306,000 | 125,000 | 303,622 | 23,613 | 71,812 | 830,047 | ||||||||||||||||||||||
Robert G. Phillips (former CEO) (2) | 2007 | 372,300 | — | 202,755 | 166,498 | 8,950,109 | 9,691,662 | |||||||||||||||||||||
2006 | 722,500 | 300,000 | 660,270 | 357,209 | 150,984 | 2,190,963 | ||||||||||||||||||||||
Dr. Ralph S. Cunningham (former CEO) (3) | 2007 | 281,828 | 171,190 | 231,645 | 23,564 | 37,896 | 746,123 | |||||||||||||||||||||
2006 | 478,667 | 250,000 | 52,815 | 13,707 | 33,208 | 828,397 | ||||||||||||||||||||||
W. Randall Fowler (4) | 2007 | 213,145 | 129,720 | 297,976 | 25,033 | 53,425 | 719,299 | |||||||||||||||||||||
2006 | 215,875 | 70,000 | 173,874 | 14,242 | 40,601 | 514,592 | ||||||||||||||||||||||
James H. Lytal | 2007 | 386,250 | 210,000 | 730,634 | 77,980 | 162,494 | 1,567,358 | |||||||||||||||||||||
2006 | 367,500 | 187,500 | 455,462 | 47,227 | 101,639 | 1,159,328 | ||||||||||||||||||||||
A. J. Teague | 2007 | 445,660 | 300,000 | 587,905 | 77,980 | 110,336 | 1,521,881 | |||||||||||||||||||||
2006 | 428,480 | 250,000 | 299,984 | 47,227 | 69,563 | 1,095,254 | ||||||||||||||||||||||
�� | ||||||||||||||||||||||||||||
Richard H. Bachmann | 2007 | 306,900 | 186,000 | 454,130 | 38,990 | 94,752 | 1,080,772 | |||||||||||||||||||||
2006 | 177,420 | 75,000 | 182,174 | 14,168 | 43,088 | 491,850 |
(1) | Mr. Creel was appointed our Chief Executive Officer effective August 1, 2007. He served as our Chief Financial Officer through August 1, 2007. Amounts presented for the years ended December 31, 2007 and 2006 reflect his tenure in both positions. | |
(2) | Mr. Phillips served as our Chief Executive Officer until his resignation effective June 30, 2007. The amount presented as “All Other Compensation” for 2007 includes a separation payment of $8,822,400. | |
(3) | Dr. Cunningham served as our Acting Chief Executive Officer from June 30, 2007 to August 1, 2007. Amounts presented for the years ended December 31, 2007 and 2006 reflect his total compensation allocated to us with respect to these periods. | |
(4) | Mr. Fowler was appointed our Chief Financial Officer effective August 1, 2007. Amounts presented for the years ended December 31, 2007 and 2006 reflect his total compensation allocated to us with respect to these periods. | |
(5) | Amounts represent discretionary annual cash awards accrued for the years ended December 31, 2007 and 2006. Cash awards are paid in February of the following year (e.g. 2007 cash awards are paid in February 2008). | |
(6) | Amounts represent expense recognized in accordance with SFAS 123(R) for the years ended December 31, 2007 and 2006 with respect to restricted unit and Employee Partnership awards. | |
(7) | Amounts represent expense recognized in accordance with SFAS 123(R) for the years ended December 31, 2007 and 2006 with respect to unit options. | |
(8) | Amounts primarily represent (i) matching contributions under funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid on equity incentive plan awards and (iii) the imputed value of life insurance premiums paid on behalf of the officer. | |
(9) | Mr. Lytal’s total compensation for 2007 includes perquisites totaling $13,111. |
182
Table of Contents
§ | Annual base salary; | ||
§ | Discretionary annual cash awards; | ||
§ | Awards under long-term incentive arrangements; and | ||
§ | Other compensation, including very limited perquisites. |
183
Table of Contents
184
Table of Contents
Grant | ||||||||||||||||||||||||
Exercise | Date Fair | |||||||||||||||||||||||
or Base | Value of | |||||||||||||||||||||||
Estimated Future Payouts Under | Price of | Unit and | ||||||||||||||||||||||
Equity Incentive Plan Awards | Option | Option | ||||||||||||||||||||||
Grant | Threshold | Target | Maximum | Awards | Awards | |||||||||||||||||||
Name | Date | (#) | (#) | (#) | ($/Unit) | ($) (1) | ||||||||||||||||||
Restricted unit awards:(2) | ||||||||||||||||||||||||
Michael A. Creel | 5/29/07 | — | 26,500 | — | — | $ | 481,926 | |||||||||||||||||
Dr. Ralph S. Cunningham | 5/29/07 | — | 26,500 | — | — | 434,812 | ||||||||||||||||||
W. Randall Fowler | 5/29/07 | — | 17,000 | — | — | 235,686 | ||||||||||||||||||
James H. Lytal | 5/29/07 | — | 26,500 | — | — | 820,440 | ||||||||||||||||||
A.J. Teague | 5/29/07 | — | 26,500 | — | — | 820,440 | ||||||||||||||||||
Richard H. Bachmann | 5/29/07 | — | 26,500 | — | — | 341,697 | ||||||||||||||||||
Unit option awards:(3) | ||||||||||||||||||||||||
Michael A. Creel | 5/29/07 | — | 60,000 | — | $ | 30.96 | 94,454 | |||||||||||||||||
Dr. Ralph S. Cunningham | 5/29/07 | — | 60,000 | — | $ | 30.96 | 85,224 | |||||||||||||||||
W. Randall Fowler | 5/29/07 | — | 45,000 | — | $ | 30.96 | 54,005 | |||||||||||||||||
James H. Lytal | 5/29/07 | — | 60,000 | — | $ | 30.96 | 160,800 | |||||||||||||||||
A.J. Teague | 5/29/07 | — | 60,000 | — | $ | 30.96 | 160,800 | |||||||||||||||||
Richard H. Bachmann | 5/29/07 | — | 60,000 | — | $ | 30.96 | 66,973 | |||||||||||||||||
EPE Unit III profits interest award:(4) | ||||||||||||||||||||||||
Michael A. Creel | 5/7/07 | — | — | — | — | 1,032,387 | ||||||||||||||||||
Dr. Ralph S. Cunningham | 5/7/07 | — | — | — | — | 931,504 | ||||||||||||||||||
W. Randall Fowler | 5/7/07 | — | — | — | — | 787,033 | ||||||||||||||||||
James H. Lytal | 5/7/07 | — | — | — | — | 1,464,621 | ||||||||||||||||||
A.J. Teague | 5/7/07 | — | — | — | — | 1,464,621 | ||||||||||||||||||
Richard H. Bachmann | 5/7/07 | — | — | — | — | 732,021 |
(1) | Amounts presented reflect that portion of grant date fair value allocable to us based on the percentage of time each Named Executive Officer spent on our consolidated business activities during 2007. 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. | |
(2) | For the period in which the restricted unit awards were outstanding during 2007, we recognized a total of $0.4 million of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods. | |
(3) | For the period in which the unit option awards were outstanding during 2007, we recognized a total of $72 thousand of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods. | |
(4) | For the period in which the profits interest awards were outstanding during 2007, we recognized a total of $1.0 million of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods. |
185
Table of Contents
186
Table of Contents
Estimated | ||||||||
Percentage | Liquidation | |||||||
Ownership | Value To Be | |||||||
of Class B | Received | |||||||
Plan Name | Interests (1) | by Officer (2) | ||||||
EPE Unit I:(3) | ||||||||
Michael A. Creel | 7.92 | % | $ | 1,100,679 | ||||
W. Randall Fowler | 5.32 | % | 739,257 | |||||
James H. Lytal | 5.32 | % | 739,257 | |||||
A.J. Teague | 5.32 | % | 739,257 | |||||
Richard H. Bachmann | 7.92 | % | 1,100,679 | |||||
EPE Unit II:(4) | ||||||||
Dr. Ralph S. Cunningham | 100.0 | % | $ | 0 | ||||
EPE Unit III:(5) | ||||||||
Michael A. Creel | 7.63 | % | $ | 0 | ||||
Dr. Ralph S. Cunningham | 7.63 | % | $ | 0 | ||||
W. Randall Fowler | 7.63 | % | $ | 0 | ||||
James H. Lytal | 6.36 | % | $ | 0 | ||||
A.J. Teague | 6.36 | % | $ | 0 | ||||
Richard H. Bachmann | 7.63 | % | $ | 0 |
(1) | Reflects Named Executive Officer share of profits interest at December 31, 2007. | |
(2) | Values based on December 31, 2007 closing price of Enterprise GP Holdings’ units of $37.02 per unit and taking into account the terms of liquidation outlined in each Employee Partnership agreement. | |
(3) | At December 31, 2007, the total profits interests of EPE Unit I would have been worth $13.9 million, of which each Named Executive Officer would have received his proportionate share. | |
(4) | The EPE Unit II Class B partnership interest had no liquidation value at December 31, 2007 due to a decrease in the market value of Enterprise GP Holdings’ units since the formation of EPE Unit II. | |
(5) | The EPE Unit III Class B partnership interests had no liquidation value at December 31, 2007 due to a decrease in the market value of Enterprise GP Holdings’ units since the formation of EPE Unit III. |
187
Table of Contents
Option Awards | Unit Awards | |||||||||||||||||||||||
Number of | Market | |||||||||||||||||||||||
Units | Number | Value | ||||||||||||||||||||||
Underlying | Option | of Units | of Units | |||||||||||||||||||||
Options | Exercise | Option | That Have | That Have | ||||||||||||||||||||
Vesting | Unexercisable | Price | Expiration | Not Vested | Not Vested | |||||||||||||||||||
Name | Date | (#) | ($/Unit) | Date | (#) | ($) | ||||||||||||||||||
Restricted unit awards: | ||||||||||||||||||||||||
Michael A. Creel | Various (1) | — | — | — | 103,053 | $ | 3,285,330 | |||||||||||||||||
Dr. Ralph S. Cunningham | Various (1) | — | — | — | 38,500 | 1,227,380 | ||||||||||||||||||
W. Randall Fowler | Various (1) | — | — | — | 58,777 | 1,873,811 | ||||||||||||||||||
James H. Lytal | Various (1) | — | — | — | 86,032 | 2,742,700 | ||||||||||||||||||
A.J. Teague | Various (1) | — | — | — | 60,500 | 1,928,740 | ||||||||||||||||||
Richard H. Bachmann | Various (1) | — | — | — | 103,053 | 3,285,330 | ||||||||||||||||||
Unit option awards: | ||||||||||||||||||||||||
Michael A. Creel: | ||||||||||||||||||||||||
May 10, 2004 option grant | 5/10/08 | 35,000 | $ | 20.00 | 5/10/14 | — | — | |||||||||||||||||
August 4, 2005 option grant | 8/04/09 | 35,000 | 26.47 | 8/04/15 | — | — | ||||||||||||||||||
May 1, 2006 option grant | 5/01/10 | 40,000 | 24.85 | 5/01/16 | — | — | ||||||||||||||||||
May 29, 2007 option grant | 5/29/11 | 60,000 | 30.96 | 5/29/17 | — | — | ||||||||||||||||||
Dr. Ralph S. Cunningham: | ||||||||||||||||||||||||
May 1, 2006 option grant | 5/01/10 | 40,000 | 24.85 | 5/01/16 | — | — | ||||||||||||||||||
May 29, 2007 option grant | 5/29/11 | 60,000 | 30.96 | 5/29/17 | — | — | ||||||||||||||||||
W. Randall Fowler: | ||||||||||||||||||||||||
May 10, 2004 option grant | 5/10/08 | 10,000 | 20.00 | 5/10/14 | — | — | ||||||||||||||||||
August 4, 2005 option grant | 8/04/09 | 25,000 | 26.47 | 8/04/15 | — | — | ||||||||||||||||||
May 1, 2006 option grant | 5/01/10 | 40,000 | 24.85 | 5/01/16 | — | — | ||||||||||||||||||
May 29, 2007 option grant | 5/29/11 | 45,000 | 30.96 | 5/29/17 | — | — | ||||||||||||||||||
James H. Lytal: | ||||||||||||||||||||||||
September 30, 2004 option grant | 9/30/08 | 35,000 | 23.18 | 9/30/14 | — | — | ||||||||||||||||||
August 4, 2005 option grant | 8/04/09 | 35,000 | 26.47 | 8/04/15 | — | — | ||||||||||||||||||
May 1, 2006 option grant | 5/01/10 | 40,000 | 24.85 | 5/01/16 | — | — | ||||||||||||||||||
May 29, 2007 option grant | 5/29/11 | 60,000 | 30.96 | 5/29/17 | — | — | ||||||||||||||||||
A.J. Teague: | ||||||||||||||||||||||||
May 10, 2004 option grant | 5/10/08 | 35,000 | 20.00 | 5/10/14 | — | — | ||||||||||||||||||
August 4, 2005 option grant | 8/04/09 | 35,000 | 26.47 | 8/04/15 | — | — | ||||||||||||||||||
May 1, 2006 option grant | 5/01/10 | 40,000 | 24.85 | 5/01/16 | — | — | ||||||||||||||||||
May 29, 2007 option grant | 5/29/11 | 60,000 | 30.96 | 5/29/17 | — | — | ||||||||||||||||||
Richard H. Bachmann: | ||||||||||||||||||||||||
May 10, 2004 option grant | 5/10/08 | 35,000 | 20.00 | 5/10/14 | — | — | ||||||||||||||||||
August 4, 2005 option grant | 8/04/09 | 35,000 | 26.47 | 8/04/15 | — | — | ||||||||||||||||||
May 1, 2006 option grant | 5/01/10 | 40,000 | 24.85 | 5/01/16 | — | — | ||||||||||||||||||
May 29, 2007 option grant | 5/29/11 | 60,000 | 30.96 | 5/29/17 | — | — |
(1) | Of the 449,915 restricted units presented in the table, 182,415 vest in 2008, 46,000 vest in 2009, 72,000 vest in 2010, and 149,500 vest in 2011. |
188
Table of Contents
Option Awards | Unit Awards | |||||||||||||||||||||||
Number of | Market | |||||||||||||||||||||||
Units | Number | Value | ||||||||||||||||||||||
Underlying | Option | of Units | of Units | |||||||||||||||||||||
Options | Exercise | Option | That Have | That Have | ||||||||||||||||||||
Vesting | Unexercisable | Price | Expiration | Not Vested | Not Vested | |||||||||||||||||||
Name | Date | (#) | ($/Unit) | Date | (#) | ($) | ||||||||||||||||||
EPE Unit I profits interest awards: | ||||||||||||||||||||||||
Michael A. Creel | 8/30/10 | — | — | — | — | 1,100,679 | ||||||||||||||||||
W. Randall Fowler | 8/30/10 | — | — | — | — | 739,257 | ||||||||||||||||||
James H. Lytal | 8/30/10 | — | — | — | — | 739,257 | ||||||||||||||||||
A.J. Teague | 8/30/10 | — | — | — | — | 739,257 | ||||||||||||||||||
Richard H. Bachmann | 8/30/10 | — | — | — | — | 1,100,679 |
Fees Earned | All | |||||||||||||||||||
or Paid | Unit | Option | Other | |||||||||||||||||
in Cash | Awards | Awards | Compensation | Total | ||||||||||||||||
Name | ($) | ($) (1) | ($) (2) | ($) (5) | ($) | |||||||||||||||
E. William Barnett | $ | 77,500 | $ | 68,562 | $ | 32,948 | (3) | $ | 3,933 | $ | 182,943 | |||||||||
Rex C. Ross | 62,500 | 19,575 | 34,530 | (4) | 890 | 117,496 | ||||||||||||||
Charles M. Rampacek | 62,500 | 19,575 | 34,530 | (4) | 890 | 117,496 |
(1) | In November 2007, each of the restricted unit grants made to our independent directors was amended to provide that the restricted units subject to such grants would immediately vest. The amounts presented for each director represent the expense recognized by us related to such restricted units during the year ended December 31, 2007. The number of restricted units that vested for each independent director was as follows: Mr. Barnett, 2,154; Mr. Ross, 615; and Mr. Rampacek, 615. | |
(2) | Amounts presented reflect the compensation expense recognized by EPGP related to unit appreciation rights (“UARs”) granted in 2006 under letter agreements. The UARs are accounted for as liability awards under SFAS 123(R) since they will be settled with cash. | |
(3) | At December 31, 2007, the fair value of UARs granted to Mr. Barnett was $96 thousand. | |
(4) | At December 31, 2007, the fair value of UARs granted to each of Mr. Ross and Mr. Rampacek was $102 thousand. | |
(5) | Amounts primarily represent the quarterly cash distributions each independent director received from restricted unit awards prior to the vesting of such awards in November 2007. |
189
Table of Contents
§ | Each independent director receives $75,000 in cash annually. Prior to August 2007, the annual retainer was $50,000 in cash and $25,000 worth of restricted units. | ||
§ | If the individual serves as chairman of a committee of the Board of Directors, then he receives an additional $15,000 in cash annually. |
Amount and | ||||||||||||
Nature of | ||||||||||||
Title of | Name and Address | Beneficial | Percent | |||||||||
Class | of Beneficial Owner | Ownership | of Class | |||||||||
Common units | Dan L. Duncan | — | (1) | — | % | |||||||
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. |
190
Table of Contents
§ | our Named Executive Officers; | ||
§ | the current Directors of EPGP; and | ||
§ | the current directors and executive officers of EPGP as a group. |
Limited Partner Ownership Interests In | ||||||||||||||||
Enterprise Products Partners L.P. | Enterprise GP Holdings L.P. | |||||||||||||||
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. | 120,086,279 | 27.6 | % | — | — | |||||||||||
Through Duncan Family Interests, Inc. | — | — | 69,203,487 | 56.2 | % | |||||||||||
Through Enterprise GP Holdings L.P. | 13,454,498 | 3.1 | % | — | — | |||||||||||
Through DFI GP Holdings L.P. | — | — | 11,819,722 | 9.6 | % | |||||||||||
Units owned by DD Securities LLC | 487,100 | * | 3,745,673 | 3.0 | % | |||||||||||
Units owned by Employee Partnerships (1) | — | — | 6,283,479 | 5.1 | % | |||||||||||
Units owned by family trusts (2) | 13,008,241 | 3.0 | % | 243,071 | * | |||||||||||
Units owned directly | 949,927 | * | — | — | ||||||||||||
Total for Dan L. Duncan | 147,986,045 | 34.0 | % | 91,295,432 | 74.1 | % | ||||||||||
Richard H. Bachmann (3) | 146,014 | * | 17,469 | * | ||||||||||||
Michael A. Creel (3) | 141,328 | * | 35,000 | * | ||||||||||||
Dr. Ralph S. Cunningham (3) | 45,106 | * | 4,000 | * | ||||||||||||
W. Randall Fowler (3) | 77,061 | * | 3,000 | * | ||||||||||||
James H. Lytal (3) | 103,325 | * | 5,000 | * | ||||||||||||
A.J. Teague (3) | 193,941 | * | 17,000 | * | ||||||||||||
E. William Barnett | 2,154 | * | — | — | ||||||||||||
Rex C. Ross | 24,285 | * | 5,400 | * | ||||||||||||
Charles M. Rampacek | 615 | * | — | — | ||||||||||||
All current directors and executive officers of EPGP, as a group, (14 individuals in total) (4) | 148,775,005 | 34.2 | % | 91,422,501 | 74.2 | % | ||||||||||
* | The beneficial ownership of each individual is less than 1% of the registrant’s common units outstanding. |
(1) | As a result of EPCO’s ownership of the general partners of the Employee Partnerships, Mr. Duncan is deemed beneficial owner of the securities held by these entities. | |
(2) | Mr. Duncan is deemed beneficial owner of the securities held by certain family trusts, the beneficiaries of which are shareholders of EPCO. | |
(3) | These individuals are Named Executive Officers. | |
(4) | Cumulatively, this group’s beneficial ownership amount includes 150,000 options to acquire common units of Enterprise Products Partners L.P. that were issued under the 1998 Plan. These options are exercisable within 60 days of the filing date of this report. |
191
Table of Contents
Duncan Energy Partners | ||||||||
Amount | ||||||||
And Nature Of | ||||||||
Name of | Beneficial | Percent of | ||||||
Beneficial Owner | Ownership | Class | ||||||
Dan L. Duncan: | ||||||||
Through EPO (1) | 5,351,571 | 26.4 | % | |||||
Units owned by family trusts | 103,100 | * | ||||||
Total for Dan L. Duncan | 5,454,671 | 26.9 | % | |||||
Richard H. Bachmann (2,3) | 10,172 | * | ||||||
Michael A. Creel (3) | 7,500 | * | ||||||
Dr. Ralph S. Cunningham (3) | 3,000 | * | ||||||
W. Randall Fowler (3,4) | 2,000 | * | ||||||
Rex C. Ross | 5,000 | * | ||||||
All current directors and executive officers of EPGP, as a group (14 individuals in total) | 5,494,943 | 27.1 | % |
* | 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 EPO in connection with its contribution of equity interests to Duncan Energy Partners in February 2007. | |
(2) | Mr. Bachmann is the Chief Executive Officer of Duncan Energy Partners. | |
(3) | These individuals are Named Executive Officers. | |
(4) | Mr. Fowler is the Chief Financial Officer of Duncan Energy Partners. |
192
Table of Contents
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 | 2,315,000 | $ | 26.18 | 1,282,256 | ||||||||
Equity compensation plans not approved by unitholders: | ||||||||||||
None. | — | — | — | |||||||||
Total for equity compensation plans | 2,315,000 | $ | 26.18 | 1,232,256 | ||||||||
(1) | Of the 2,315,000 unit options outstanding at December 31, 2007, 335,000 were immediately exercisable and an additional 285,000, 380,000, 510,000 and 805,000 options are exercisable in 2008, 2009, 2010 and 2011, respectively. |
193
Table of Contents
§ | EPCO and its private company subsidiaries; | ||
§ | EPGP, our sole general partner; | ||
§ | Enterprise GP Holdings, which owns and controls our general partner; | ||
§ | the Employee Partnerships; | ||
§ | TEPPCO, which is owned and controlled by Enterprise GP Holdings; and | ||
§ | Energy Transfer Equity, an equity method investment of Enterprise GP Holdings. |
194
Table of Contents
§ | EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel 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. |
195
Table of Contents
§ | If a business opportunity to acquire “equity securities” (as defined below) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), 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) 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 want to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP 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 $100 million, 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, EPGP and DEP GP, Enterprise Products Partners will have the second right to pursue such acquisition. Enterprise Products Partners will be presumed to want to acquire the equity securities until such time as EPGP advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing EPGP’s Chief Executive Officer and ACG Committee. | |||
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition. | |||
In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to TEPPCO (including 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 Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy Partners (including DEP GP), Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan |
196
Table of Contents
Energy Partners. It will be presumed that Enterprise Products Partners will pursue the business opportunity until such time as its general partner advises the EPCO Group, EPE Holdings and DEP GP that it has 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 EPGP after consultation with and subject to the approval of the ACG Committee of EPGP. If the purchase price or cost is reasonably likely to be less than $100 million, the Chief Executive Officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee. | |||
In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition. | |||
In the event that Enterprise Products Partners abandons the business opportunity for itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity. It will be presumed that Enterprise GP Holdings will pursue such acquisition until such time as its general partner declines such opportunity (in accordance with the procedures described above for Enterprise Products Partners) and advises the EPCO Group that it has abandoned the pursuit of such business opportunity. Should this occur, the EPCO Group may either pursue the business opportunity or offer the business opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates. |
197
Table of Contents
198
Table of Contents
§ | 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 $268.0 million for the year ended December 31, 2007. In addition, we furnished $1.1 million in letters of credit on behalf of Evangeline at December 31, 2007. | ||
§ | We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. For the year ended December 31, 2007, we recorded revenues of $17.3 million from Promix and paid Promix $30.4 million for its services to us. | ||
§ | We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $9.3 million for such services during the year ended December 31, 2007. |
199
Table of Contents
§ | indemnification for certain environmental liabilities, tax liabilities and right-of-way defects; | ||
§ | reimbursement of certain expenditures incurred by DEP South Texas NGL and Mont Belvieu Caverns; | ||
§ | a right of first refusal to EPO in Duncan Energy Partners’ current and future subsidiaries 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 in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct its business that arise through February 5, 2010; and | ||
§ | certain income tax liabilities attributable to the operation of the assets contributed to Duncan Energy Partners in connection with its initial public offering prior to February 5, 2007. |
200
Table of Contents
§ | the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest; | ||
§ | the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership); | ||
§ | any customary or accepted industry practices and any customary or historical dealings with a particular person; | ||
§ | any applicable generally accepted accounting or engineering practices or principles; | ||
§ | the relative cost of capital of the parties and the consequent rates of return to the equity holders of the parties; and | ||
§ | such additional factors as the committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. |
201
Table of Contents
§ | 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 deemed 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. |
202
Table of Contents
For Year Ended December 31, | ||||||||
2007 | 2006 | |||||||
Audit Fees (1) | $ | 3,825 | $ | 4,476 | ||||
Audit-Related Fees (2) | 79 | 13 | ||||||
Tax Fees (3) | 341 | 297 | ||||||
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 and partnership tax planning. | |
(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. |
203
Table of Contents
2.1 | Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003). | |
2.2 | Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004). | |
2.3 | Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003). | |
2.4 | Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004). |
204
Table of Contents
2.5 | Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003). | |
3.1 | Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 8, 2007). | |
3.2 | 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). | |
3.3 | First Amendment to Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3, 2008). | |
3.4 | Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of November 7, 2007 (incorporated by reference to Exhibit 3.2 to Form 10-Q filed November 8, 2007). | |
3.5 | Limited Liability Company Agreement of Enterprise Products Operating LLC dated as of June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed on August 8, 2007). | |
3.6 | 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). | |
3.7 | 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). | |
3.8 | 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). | |
3.9 | Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P., dated February 5, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K/A filed February 5, 2007). | |
3.10 | First Amendment to Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K filed on January 3, 2008). | |
4.1 | 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). | |
4.2 | Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000). | |
4.3 | First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003). | |
4.4 | Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003). | |
4.5 | Third Supplemental Indenture dated as of June 30, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed on August 8, 2007) . | |
4.6 | Amended and Restated Revolving Credit Agreement dated as of November 19, 2007 among Enterprise Products Operating LLC, the financial institutions party thereto as lenders, Wachovia Bank, National Association, as Administrative Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 20, 2007). |
205
Table of Contents
4.7 | Amended and Restated Guaranty Agreement dated as of November 19, 2007 executed by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed on November 20, 2007). | |
4.8 | 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). | |
4.9 | 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). | |
4.10 | 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). | |
4.11 | 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). | |
4.12 | 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). | |
4.13 | 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). | |
4.14 | 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). | |
4.15 | 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). | |
4.16 | 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). | |
4.17 | Ninth Supplemental Indenture, dated as of May 24, 2007, by and 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 the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007). | |
4.18 | Tenth Supplemental Indenture, dated as of June 30, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007). | |
4.19 | Eleventh Supplemental Indenture, dated as of September 4, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on September 5, 2007). | |
4.20 | 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). |
206
Table of Contents
4.21 | 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). | |
4.22 | 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). | |
4.23 | 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). | |
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 | 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). | |
4.29 | 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). | |
4.30 | 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). | |
4.31 | Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K file July 19, 2006). | |
4.32 | Global Note representing $800,000,000 principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 8, 2007). | |
4.33 | 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). | |
4.34 | Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007). | |
4.35 | First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (Incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006). | |
4.36 | 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). | |
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*** | Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of November 9 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed on November 8, 2007). | |
10.3*** | Form of Option Grant Award under Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 10-Q filed on November 8, 2007). |
207
Table of Contents
10.4*** | Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on November 8, 2007). | |
10.5*** | 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). | |
10.6*** | First Amendment to EPE Unit L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.3 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007). | |
10.7*** | EPE Unit II, L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.13 to Form 10-K filed on February 28, 2007). | |
10.8*** | First Amendment to EPE Unit II, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.4 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007). | |
10.9*** | EPE Unit III, L.P. Agreement of Limited Partnership dated May 7, 2007 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P. on May 10, 2007). | |
10.10*** | First Amendment to EPE Unit III, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.5 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007). | |
10.11*** | 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). | |
10.12*** | 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). | |
10.13*** | 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). | |
10.14*** | 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). | |
10.15*** | Enterprise Products 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit A to the Proxy Statement filed on December 31, 2007). | |
10.16 | 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). | |
10.17 | First Amendment to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007 (incorporated by reference to Exhibit 10.8 to Form 10-K filed on February 28, 2007). | |
10.18 | Second Amendment to Fourth Amended and Restated Administrative Services Agreement dated August 7, 2007, but effective as of May 7, 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007). | |
10.19 | 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). | |
10.20 | 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). |
208
Table of Contents
10.21 | Agreement and Release, dated May 31, 2007, between EPCO, Inc. and Robert G. Phillips (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on August 8, 2007). | |
10.22 | Revolving Credit Agreement, dated as of January 5, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.20 to Amendment No. 2 to Form S-1 Registration Statement (Reg. No. 333-138371) filed January 12, 2007). | |
10.23 | First Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.2 to Form 10-Q filed August 8, 2007 by Duncan Energy Partners). | |
12.1# | Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2007, 2006, 2005, 2004 and 2003. | |
21.1# | List of subsidiaries as of February 1, 2008. | |
23.1# | Consent of Deloitte & Touche LLP dated February 28, 2008. | |
31.1# | Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K. | |
31.2# | Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K. | |
32.1# | Section 1350 certification of Michael A. Creel for the December 31, 2007 annual report on Form 10-K. | |
32.2# | Section 1350 certification of W. Randall Fowler for the December 31, 2007 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. |
209
Table of Contents
ENTERPRISE PRODUCTS PARTNERS L.P. | ||||||
(A Delaware Limited Partnership) | ||||||
By: | Enterprise Products GP, LLC, as general partner | |||||
By: | /s/Michael J. Knesek | |||||
Name: | Michael J. Knesek | |||||
Title: | Senior Vice President, Controller and | |||||
Principal Accounting Officer |
Signature | Title (Position with Enterprise Products GP, LLC) | |
/s/ Dan L. Duncan | Director and Chairman | |
/s/ Michael A. Creel | Director, President and Chief Executive Officer | |
/s/ W. Randall Fowler | Director, Executive Vice President and Chief Financial Officer | |
/s/ Richard H. Bachmann | Director, Executive Vice President, Chief Legal Officer and Secretary | |
/s/ Dr. Ralph S. Cunningham | Director | |
/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 |
210
Table of Contents
Exhibits | Description of Exhibits | |
2.1 | Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003). | |
2.2 | Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004). | |
2.3 | Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003). | |
2.4 | Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004). | |
2.5 | Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003). | |
3.1 | Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 8, 2007). | |
3.2 | 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). | |
3.3 | First Amendment to Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3, 2008). | |
3.4 | Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of November 7, 2007 (incorporated by reference to Exhibit 3.2 to Form 10-Q filed November 8, 2007). | |
3.5 | Limited Liability Company Agreement of Enterprise Products Operating LLC dated as of June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed on August 8, 2007). | |
3.6 | 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). | |
3.7 | 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). | |
3.8 | 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). | |
3.9 | Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P., dated February 5, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K/A filed February 5, 2007). | |
3.10 | First Amendment to Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K filed on January 3, 2008). | |
4.1 | 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). | |
4.2 | Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000). |
211
Table of Contents
Exhibits | Description of Exhibits | |
4.3 | First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003). | |
4.4 | Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003). | |
4.5 | Third Supplemental Indenture dated as of June 30, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed on August 8, 2007) . | |
4.6 | Amended and Restated Revolving Credit Agreement dated as of November 19, 2007 among Enterprise Products Operating LLC, the financial institutions party thereto as lenders, Wachovia Bank, National Association, as Administrative Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 20, 2007). | |
4.7 | Amended and Restated Guaranty Agreement dated as of November 19, 2007 executed by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed on November 20, 2007). | |
4.8 | 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). | |
4.9 | 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). | |
4.10 | 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). | |
4.11 | 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). | |
4.12 | 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). | |
4.13 | 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). | |
4.14 | 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). | |
4.15 | 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). |
212
Table of Contents
Exhibits | Description of Exhibits | |
4.16 | 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). | |
4.17 | Ninth Supplemental Indenture, dated as of May 24, 2007, by and 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 the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007). | |
4.18 | Tenth Supplemental Indenture, dated as of June 30, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007). | |
4.19 | Eleventh Supplemental Indenture, dated as of September 4, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on September 5, 2007). | |
4.20 | 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). | |
4.21 | 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). | |
4.22 | 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). | |
4.23 | 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). | |
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). | |
4.16 | 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 | 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). | |
4.29 | 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). | |
4.30 | 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). | |
4.31 | Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K file July 19, 2006). | |
4.32 | Global Note representing $800,000,000 principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 8, 2007). | |
4.33 | 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). |
213
Table of Contents
Exhibits | Description of Exhibits | |
4.34 | Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007). | |
4.35 | First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (Incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006). | |
4.36 | 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). | |
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*** | Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of November 9 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed on November 8, 2007). | |
10.3*** | Form of Option Grant Award under Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 10-Q filed on November 8, 2007). | |
10.4*** | Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on November 8, 2007). | |
10.5*** | 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). | |
10.6*** | First Amendment to EPE Unit L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.3 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007). | |
10.7*** | EPE Unit II, L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.13 to Form 10-K filed on February 28, 2007). | |
10.8*** | First Amendment to EPE Unit II, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.4 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007). | |
10.9*** | EPE Unit III, L.P. Agreement of Limited Partnership dated May 7, 2007 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P. on May 10, 2007). | |
10.10*** | First Amendment to EPE Unit III, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.5 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007). | |
10.11*** | 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). | |
10.12*** | 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). | |
10.13*** | 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). | |
10.14*** | 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). | |
10.15 | Fourth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise |
214
Table of Contents
Exhibits | Description of Exhibits | |
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). | ||
10.16 | First Amendment to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007 (incorporated by reference to Exhibit 10.8 to Form 10-K filed on February 28, 2007). | |
10.17 | Second Amendment to Fourth Amended and Restated Administrative Services Agreement dated August 7, 2007, but effective as of May 7, 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007). | |
10.18 | 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). | |
10.19 | 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). | |
10.20 | Agreement and Release, dated May 31, 2007, between EPCO, Inc. and Robert G. Phillips (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on August 8, 2007). | |
10.21 | Revolving Credit Agreement, dated as of January 5, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.20 to Amendment No. 2 to Form S-1 Registration Statement (Reg. No. 333-138371) filed January 12, 2007). | |
10.22 | First Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.2 to Form 10-Q filed August 8, 2007 by Duncan Energy Partners). | |
12.1# | Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2007, 2006, 2005, 2004 and 2003. | |
21.1# | List of subsidiaries as of February 1, 2008. | |
23.1# | Consent of Deloitte & Touche LLP. | |
31.1# | Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K. | |
31.2# | Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K. | |
32.1# | Section 1350 certification of Michael A. Creel for the December 31, 2007 annual report on Form 10-K. | |
32.2# | Section 1350 certification of W. Randall Fowler for the December 31, 2007 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. |
215
Table of Contents
*** | Identifies management contract and compensatory plan arrangements. | |
# | Filed with this report. |
216