TEPPCO Partners, L.P. 10-K 2009
Documents found in this filing:
TEPPCO PARTNERS, L.P.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” or “TEPPCO” are intended to mean the business and operations of TEPPCO Partners, L.P. and its consolidated subsidiaries.
References to “TE Products,” “TCTM,” “TEPPCO Midstream” and “TEPPCO Marine Services” mean TE Products Pipeline Company, LLC, TCTM, L.P., TEPPCO Midstream Companies, LLC and TEPPCO Marine Services, LLC, our subsidiaries.
References to “General Partner” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO.
References to “TEPPCO GP” mean TEPPCO GP, Inc., our subsidiary, which is the general partner or manager of TE Products, TCTM and TEPPCO Midstream.
References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded partnership that owns our General Partner and Enterprise Products GP, LLC, the general partner of Enterprise Products Partners L.P.
References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., and its consolidated subsidiaries, a publicly traded Delaware limited partnership, which is an affiliate of ours.
References to “EPCO” mean EPCO, Inc., a privately-held company that is affiliated with our General Partner.
References to “Enterprise Products GP” mean Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners.
References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.
References to “DFI” mean Duncan Family Interests, Inc. and “DFIGP” mean DFI GP Holdings L.P. DFI and DFIGP are private company affiliates of EPCO. Enterprise GP Holdings acquired its ownership interests in us and our General Partner from DFI and DFIGP.
References to “Dan Duncan LLC” mean Dan Duncan LLC, a privately held company that owns EPE Holdings. Dan L. Duncan owns and controls Dan Duncan LLC.
References to “Duncan Energy Partners” mean Duncan Energy Partners L.P. and its consolidated subsidiaries, a publicly traded Delaware limited partnership and a consolidated subsidiary of Enterprise Products Partners.
We, Enterprise Products Partners, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings, Duncan Energy Partners, DFI, DFIGP and our General Partner are affiliates and under common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO and the controlling member of Dan Duncan LLC.
As generally used in the energy industry and in this discussion, the identified terms have the following meanings:
The matters discussed in this Annual Report on Form 10-K (this “Report”) include “forward-looking statements.” All statements that express belief, expectation, estimates or intentions, as well as those that are not statements of historical facts are forward-looking statements. The words “proposed”, “anticipate”, “potential”, “may”, “will”, “could”, “should”, “expect”, “estimate”, “believe”, “intend”, “plan”, “seek”, “outlook” and similar expressions are intended to identify forward-looking statements. Without limiting the broader description of forward-looking statements above, we specifically note that statements included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as future distributions, estimated future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, anticipated outcome of various legal and regulatory proceedings, plans, references to future success or events, anticipated market or industry developments, management’s outlook for future periods, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. While we believe our expectations reflected in these forward-looking statements are reasonable, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including general economic, market or business conditions, the stability and liquidity of the financial markets, the opportunities (or lack thereof) that may be presented to and pursued by us, competitive actions by other pipeline or energy transportation companies, changes in laws or regulations and other factors, many of which are beyond our control. For example, the demand for refined products is dependent upon the price, prevailing economic conditions and demographic changes in the markets served, trucking and railroad freight, agricultural usage and military usage; the demand for propane is sensitive to the weather and prevailing economic conditions; the demand for petrochemicals is dependent upon prices for products produced from petrochemicals; the demand for crude oil and petroleum products is dependent upon the price of crude oil and the products produced from the refining of crude oil; the demand for natural gas is dependent upon the price of natural gas and the locations in which natural gas is drilled; and the demand for marine transportation services is dependent upon the demand for products and prevailing economic conditions. Further, the success of our marine services business is dependent upon, among other things, our ability to effectively assimilate and provide for the operation of that business, maintain key personnel and customer relationships and obtain favorable contract renewals. We are also subject to regulatory factors such as the amounts we are allowed to charge our customers for the services we provide on our regulated pipeline systems and the cost and ability of complying with government regulations of the marine transportation industry. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to or effect on us or our business or operations. Also note that we provide additional cautionary discussion of risks and uncertainties under the captions “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Report.
The forward-looking statements contained in this Report speak only as of the date hereof. Except as required by the federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Report and in our future periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Report may not occur.
Items 1 and 2. Business and Properties
We are a publicly traded, diversified energy logistics company with operations that span much of the continental United States. Our limited partner units (“Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “TPP”. We were formed in March 1990 as a Delaware limited partnership.
We own and operate an extensive network of assets that facilitate the movement, marketing, gathering and storage of various commodities and energy-related products. Our pipeline network is comprised of approximately 12,500 miles of pipelines that gather and transport refined petroleum products, crude oil, natural gas, liquefied petroleum gases (“LPGs”) and natural gas liquids (“NGLs”), including one of the largest common carrier pipelines for refined petroleum products and LPGs in the United States. We also own a marine business that transports refined petroleum products, crude oil, asphalt, condensate, heavy fuel oil and other heated oil products via tow boats and tank barges. In addition, we own interests in Seaway Crude Pipeline Company (“Seaway”), Centennial Pipeline LLC (“Centennial”), Jonah Gas Gathering Company (“Jonah”) and Texas Offshore Port System and an undivided ownership interest in the Basin Pipeline (“Basin”). We operate and report in four business segments:
Our reportable segments offer different products and services and are managed separately because each requires different business strategies. We operate through TE Products, TCTM and TEPPCO Midstream, and beginning February 1, 2008, through TEPPCO Marine Services. Texas Eastern Products Pipeline Company, LLC, a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. We hold a 99.999% limited partner interest in TCTM and 99.999% membership interests in each of TE Products and TEPPCO Midstream and a 100% membership interest in TEPPCO Marine Services. TEPPCO GP holds a 0.001% general partner interest in TCTM and a 0.001% managing member interest in each of TE Products and TEPPCO Midstream. Our interstate pipeline transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). We refer to refined products, LPGs, petrochemicals, crude oil, lubrication oils and specialty chemicals, NGLs, natural gas, asphalt, heavy fuel oil and other heated oil products in this Report, collectively, as “petroleum products” or “products.”
Dan L. Duncan and certain of his affiliates, including Enterprise GP Holdings and Dan Duncan LLC, a privately held company controlled by him, control us, our General Partner and Enterprise Products Partners and its affiliates, including Duncan Energy Partners. Enterprise GP Holdings owns and controls the 2% general partner interest in us and has the right (through its 100% ownership of our General Partner) to receive the incentive distribution rights associated with the general partner interest. Enterprise GP Holdings, DFI, DFIGP and other entities controlled by Mr. Duncan own 17,073,315, or 16.3%, of our Units.
We do not directly employ any officers or other persons responsible for managing our operations. Under an amended and restated administrative services agreement (“ASA”), we reimburse EPCO for all costs and expenses it incurs in providing management, administrative and operating services for us, including compensation of employees (i.e., salaries, medical benefits and retirement benefits). Please see Item 13. Certain Relationships and Related Transactions, and Director Independence for additional information.
At December 31, 2008, 2007 and 2006, we had outstanding 104,704,861, 89,911,532 and 89,804,829 Units, respectively.
Our primary business objective is to grow TEPPCO’s sustainable cash flow and increase cash distributions to our unitholders. The key elements of our strategy are to:
Please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Overview of Business – Other Considerations” for additional information that impacts our ability to effectively execute our business strategy.
On February 1, 2008, we, through our subsidiary, TEPPCO Marine Services, entered the marine transportation business for refined products, crude oil and condensate through the purchase of 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements from Cenac Towing Co., Inc., Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”), for approximately $444.7 million in cash and newly issued Units. Additionally, we assumed $63.2 million of Cenac’s long-term debt. We financed the cash portion of the acquisition consideration and repaid the assumed debt with borrowings under our term credit agreement.
On February 29, 2008, we expanded our Marine Services Segment with the acquisition of marine assets from Horizon Maritime, L.L.C. (“Horizon”), a privately-held Houston-based company and an affiliate of Mr. Cenac for $80.8 million in cash. We acquired 7 tow boats, 17 tank barges, rights to two tow boats under construction and certain related commercial and other agreements (or the associated economic benefits). In April 2008, we paid $3.0 million to Horizon pursuant to the purchase agreement upon delivery of one of the tow boats under construction, and in June 2008, we paid $3.8 million upon delivery of the second tow boat. We financed the acquisition with borrowings under our term credit agreement.
For additional information, please see “– Marine Services Segment – Barge Transportation of Petroleum Products.”
On August 1, 2008, we purchased lubrication and other fuel oil assets, located in Wyoming, from Quality Petroleum, Inc. for approximately $6.8 million. The assets, included in our Upstream Segment, consist of operating inventory, buildings, land and various equipment and the assignment of certain distributor agreements. We funded the purchase through borrowings under our revolving credit facility. For additional information, please see “– Upstream Segment – Gathering, Transportation, Marketing and Storage of Crude Oil.”
Organic Growth Projects
During 2008, our organic growth projects included the following:
Jonah System Expansions
In June 2008, Jonah completed its Phase V expansion, which increased the combined gathering capacity of our Jonah and Pinedale fields systems from 1.5 Bcf per day to 2.35 Bcf per day. The increased capacity from the expansion has reduced system operating pressures and increased production rates and ultimate reserve recoveries.
In early 2008, Jonah began an expansion of the portion of its system serving the Pinedale field, which is expected to further increase the combined system capacity of our Jonah and Pinedale fields from 2.35 Bcf per day to approximately 2.55 Bcf per day. This project will include an additional 17,000 horsepower of compression at the Paradise and Bird Canyon stations in Sublette County, Wyoming and involve construction of approximately 52 miles of 30-inch and 24-inch diameter pipelines. The pipelines and 10,200 horsepower of compression were completed and placed in service in November 2008. The remaining 6,800 horsepower of compression at Bird Canyon is expected to be completed in mid 2009. The total anticipated cost of this system expansion is expected to be approximately $125.0 million. Our share of the costs of the construction is expected to be 80.64%, and Enterprise Products Partners’ share is expected to be 19.36%. Enterprise Products Partners is managing the construction project.
For additional information, please see “– Midstream Segment – Gathering of Natural Gas, Transportation of NGLs and Fractionation of NGLs.”
Texas Offshore Port System Joint Venture
In August 2008, we, together with Enterprise Products Partners and Oiltanking Holding Americas, Inc. (“Oiltanking”), formed Texas Offshore Port System, a joint venture to design, construct, operate and own a new Texas offshore crude oil port and pipeline system to facilitate delivery of waterborne crude oil to refining centers located along the upper Texas Gulf Coast. The joint venture’s primary project, referred to as “TOPS,” includes (i) an offshore port (which will be located approximately 36 miles from Freeport, Texas), (ii) an onshore storage facility with approximately 3.9 million barrels of total crude oil storage capacity, and (iii) an 85-mile pipeline system that will have the capacity to deliver up to 1.8 million barrels per day of crude oil, that will extend from the offshore port to a storage facility near Texas City, Texas. The joint venture’s complementary project, referred to as the Port Arthur Crude Oil Express (“PACE”) will transport crude oil from Texas City, including crude oil from TOPS, and will consist of a 75-mile pipeline and 1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas, area. Development of the TOPS and PACE projects is supported by long-term contracts with affiliates of Motiva and Exxon Mobil Corporation, which have committed a combined 725,000 barrels per day of crude oil to the projects. The timing of the construction and related capital costs of the TOPS and PACE projects will be affected by the acquisition of requisite permits. For additional information, please see “– Upstream Segment – Gathering, Transportation, Marketing and Storage of Crude Oil.”
Expansion of Inland Waterway Distribution Network
In August 2008, we commenced operations at our new 500,000 barrel Boligee refined products terminal in Greene County, Alabama. Located along the Tennessee-Tombigbee waterway, the facility provides gasoline, diesel and ethanol storage capabilities and provides for direct access to most U.S. Gulf Coast refining centers through an interconnect with the Colonial pipeline system. Additionally, the intermodal terminal offers truck and marine transportation options and future rail capabilities. The facility also serves as an origination point for refined products delivered to our 130,000 barrel terminal in Aberdeen, Mississippi.
Debt Financings and Retirements
In January 2008, TE Products retired all of its outstanding long-term debt by repaying at maturity $180.0 million principal amount of its 6.45% TE Products Senior Notes due 2008 and redeeming the remaining $175.0 million principal amount of its 7.51% TE Products Senior Notes due 2028. The redemption price for the 7.51% TE Products Senior Notes due 2028 was 103.755% (or $181.6 million, which included a $6.6 million make-whole premium) of the principal amount plus accrued and unpaid interest at January 28, 2008, the date of redemption, of $0.5 million. We funded the retirement of the TE Products debt with borrowings under our term credit agreement.
On March 27, 2008, we issued and sold in an underwritten public offering (i) $250.0 million principal amount of 5.90% Senior Notes due 2013, (ii) $350.0 million principal amount of 6.65% Senior Notes due 2018, and (iii) $400.0 million principal amount of 7.55% Senior Notes due 2038. The proceeds of this offering were used to repay borrowings oustanding under our term credit agreement, which was terminated in March 2008 (see Note 12 in the Notes to Consolidated Financial Statements).
On July 17, 2008, commitments under our revolving credit facility (“Revolving Credit Facility”) were increased from $700.0 million to $950.0 million. For further information about our Revolving Credit Facility and availability of commitments thereunder, please refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Other Considerations – Credit Facilities.”
Equity Offering and Registration Statement
In September 2008, we filed a universal shelf registration statement with the SEC that allows us to issue an unlimited amount of debt and equity securities and removed from registration securities remaining under our previous universal shelf registration statement.
On September 9, 2008, we issued and sold in an underwritten public offering 9.2 million Units at a price to the public of $29.00 per Unit, including 1.2 million Units sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering. The proceeds from the offering, net of underwriting discount and offering expenses, totaled approximately $257.0 million. Concurrently with this offering, we sold 241,380 unregistered Units at the public offering price of $29.00 to TEPPCO Unit L.P. (“TEPPCO Unit”), an affiliate of EPCO in which certain EPCO employees who perform services for us, including certain executive officers, were issued Class B limited partner interests to incentivize them to enhance the long-term value of our Units. The net proceeds from the offering and the unregistered issuance to TEPPCO Unit were used to reduce indebtedness under our Revolving Credit Facility. For additional information regarding TEPPCO Unit and the equity-based compensatory awards issued therein, please see Note 4 in the Notes to Consolidated Financial Statements.
Financial Information by Business Segment
The following is a discussion of the business and properties of our four business segments. See Note 14 in the Notes to Consolidated Financial Statements for financial information by segment.
Downstream Segment – Transportation and Storage of Refined Products, LPGs and Petrochemicals
We conduct business in our Downstream Segment through the following:
Properties and Operations
Our Downstream Segment owns, operates or has investments in properties located in 15 states. The operations of the Downstream Segment consist of interstate transportation, storage and terminaling of refined products and LPGs; intrastate transportation of petrochemicals; distribution and marketing operations, including terminaling services and other ancillary services. Other activities are related to the intrastate transportation of petrochemicals under a throughput and deficiency contract.
TE Products is one of the largest pipeline common carriers of refined products and LPGs in the United States. The Downstream Segment, primarily through TE Products, owns and operates an approximately 4,700-mile pipeline system (together with the receiving, storage and terminaling facilities mentioned below, the “Products Pipeline System”) extending from southeast Texas through the central and midwestern United States to the northeastern United States.
As an interstate common carrier, we offer interstate transportation services, pursuant to tariffs filed with the FERC, to any shipper of refined products and LPGs who requests these services, provided that the conditions and specifications contained in the applicable tariff are satisfied. In addition to services for transportation of products, we also provide storage and other related services at key points along our Products Pipeline System. Substantially all of the refined products and LPGs transported and stored in our Products Pipeline System are owned by our customers. The products are received from refineries, connecting pipelines and bulk and marine terminals located principally on the southern end of the pipeline system. The U.S. Gulf Coast region is a significant supply source for our facilities and is a major hub for petroleum refining. The products are stored and scheduled into the pipeline in accordance with customer nominations and shipped to delivery terminals for ultimate delivery to the final distributor (including gas stations and retail propane distribution centers) or to other pipelines. Pipelines are generally the lowest cost method for intermediate and long-haul overland transportation of refined products and LPGs.
The Products Pipeline System includes 35 storage facilities with an aggregate storage capacity of 21 million barrels of refined products and 6 million barrels of LPGs, including leased storage capacity. The Products Pipeline System makes deliveries to customers at 63 locations including 20 truck racks, rail car facilities and marine facilities that we own. Deliveries to other pipelines occur at various facilities owned by TE Products or by third parties.
TE Products owns one active marine receiving terminal at Providence, Rhode Island. This facility includes a 400,000-barrel refrigerated storage tank along with ship unloading and truck loading facilities. We operate the terminal and provide propane loading services to one customer. Our ability in the Downstream Segment to serve propane markets in the Northeast is enhanced by this terminal, which is not physically connected to the Products Pipeline System.
Through TTMC, we conduct distribution and marketing operations whereby we provide terminaling services at our Aberdeen and Boligee terminals. The Aberdeen terminal, located along the Tennessee-Tombigbee Waterway system in Aberdeen, Mississippi, has storage capacity of 130,000 barrels for gasoline and diesel, which are supplied by barge for delivery to local markets, including Tupelo and Columbus, Mississippi. In August 2008, we commenced operations at a 500,000 barrel refined products terminal in Boligee in Greene County, Alabama.
Located along the Tennessee-Tombigbee waterway system, the facility provides gasoline, diesel and ethanol storage capabilities and provides for direct access to most U.S. Gulf Coast refining centers through an interconnect with the Colonial pipeline system. Additionally, the intermodal terminal offers truck and marine transportation options and future rail capabilities. The facility also serves as an origination point for refined products delivered to our Aberdeen terminal.
Our Downstream Segment also includes the operations of the northern portion of the Dean Pipeline, which transports refinery grade propylene (“RGP”) from Mont Belvieu, Texas, to Point Comfort, Texas.
The following table lists the material properties and investments of and ownership percentages in our Downstream Segment assets as of December 31, 2008:
Refined products and LPGs deliveries in MMBbls for the years ended December 31, 2008, 2007 and 2006, were as follows:
Refined Products, LPGs and Petrochemical Pipeline Systems
The Products Pipeline System is comprised of a 20-inch diameter line extending in a generally northeasterly direction from Baytown, Texas (located approximately 30 miles east of Houston), to a point in southwest Ohio near Lebanon, Ohio and our Todhunter facility near Middleton, Ohio. Major origination facilities for this 20-inch system are in Baytown, Texas, Beaumont, Texas, and Mont Belvieu, Texas. The Products Pipeline System continues eastward from our Todhunter facility to Greensburg, Pennsylvania, at which point it branches into two segments, one ending in Selkirk, New York (near Albany), and the other ending at Marcus Hook, Pennsylvania (near Philadelphia). The Products Pipeline System east of our Todhunter facility and ending in Selkirk is an 8-inch
diameter line, and the line starting at Greensburg and ending at Marcus Hook varies in diameter from 6 inches to 8 inches. A second line, which also originates at Baytown, is 16 inches in diameter until it reaches Beaumont, Texas, at which point it reduces to a 14-inch diameter line. This second line extends along the same path as the 20-inch diameter line to the Products Pipeline System’s terminal in El Dorado, Arkansas, before continuing as a 16-inch diameter line to Seymour, Indiana.
The Products Pipeline System also includes a 14-inch diameter line from Seymour to Chicago, Illinois, and a 10-inch diameter line running from Lebanon to Lima, Ohio. This 10-inch diameter pipeline connects to the Buckeye Pipe Line Company system that serves, among others, markets in Michigan and eastern Ohio. The Products Pipeline System also has a 6-inch diameter pipeline connection to the Greater Cincinnati/Northern Kentucky International Airport.
In addition, the Products Pipeline System contains numerous lines, ranging in size from 6 inches to 20 inches in diameter, associated with the gathering and distribution system, extending from Baytown to Beaumont; Texas City to Baytown; Pasadena, Texas, to Baytown; Mont Belvieu to Beaumont; and an 8-inch diameter pipeline connection to the George Bush Intercontinental Airport terminal in Houston.
The Products Pipeline System also has various diameter lines that extend laterally from El Dorado to Helena, Arkansas, from Shreveport, Louisiana, to El Dorado and from McRae, Arkansas, to Memphis, Tennessee. The line from El Dorado to Helena has a 10-inch diameter. The line from Shreveport to El Dorado varies in diameter from 8 inches to 10 inches. The line from McRae to Memphis has a 12-inch diameter.
TE Products also owns three parallel 12-inch diameter common carrier petrochemical pipelines between Mont Belvieu and Port Arthur. Each of these pipelines is approximately 70 miles in length. The pipelines transport ethylene, propylene, natural gasoline and naphtha. We entered into a 20-year agreement in 2002 with a major petrochemical producer for guaranteed throughput commitments on these three pipelines.
Our Downstream Segment also includes the operations of the northern portion of the Dean Pipeline, which consists of 138 miles of pipeline transporting RGP from Mont Belvieu to Point Comfort.
In December 2006, we signed an agreement with Motiva for us to construct and operate a new refined products storage facility to support the expansion of Motiva’s refinery in Port Arthur, Texas. Under the terms of the agreement, we are constructing a 5.4 million barrel refined products storage facility for gasoline and distillates. The agreement also provides for a 15-year throughput and dedication of volume, which will commence upon completion of the refinery expansion or July 1, 2010, whichever comes first. The project includes the construction of 20 storage tanks, five 5.4-mile product pipelines connecting the storage facility to Motiva’s refinery, 21,000 horsepower of pumping capacity, and distribution pipeline connections to the Colonial, Explorer and Magtex pipelines. As a part of a separate but complementary initiative, we are constructing an 11-mile, 20-inch pipeline to connect the new storage facility in Port Arthur to our refined products terminal in Beaumont, Texas, which is one of the primary origination facilities for our mainline system. These projects will facilitate connections to additional markets through the Colonial, Explorer and Magtex pipeline systems and provide the Motiva refinery with access to our pipeline system. The total cost of the project is expected to be approximately $355.0 million, which includes $25.0 million for the 11-mile, 20-inch pipeline, $24.0 million of capitalized interest and $17.0 million of mutually agreed upon scope changes requested by Motiva. Through December 31, 2008, we have spent approximately $170.1 million on this construction project. Under the terms of the agreement, if Motiva cancels the agreement prior to the commencement date of the project, Motiva will reimburse us the actual reasonable expenses we have incurred after the effective date of the agreement, including both internal and external costs that would be capitalized as a part of the project, plus a ten percent cancellation fee.
Centennial Pipeline Equity Investment
TE Products owns a 50% ownership interest in Centennial and Marathon Petroleum Company LLC (“Marathon”) owns the remaining 50% interest. Centennial, which commenced operations in April 2002, owns an interstate refined products pipeline extending from the upper Texas Gulf Coast to central Illinois. Centennial constructed a 74-mile, 24-inch diameter pipeline connecting TE Products’ facility in Beaumont, Texas, with an existing 720-mile, 26-inch diameter pipeline extending from Longville, Louisiana, to Bourbon, Illinois. The
Centennial pipeline intersects TE Products’ existing mainline pipeline near Creal Springs, Illinois, where Centennial constructed a two million barrel refined products storage terminal. The Centennial pipeline loops the Products Pipeline System between Beaumont, Texas and southern Illinois. Looping the Products Pipeline System permits effective supply of product to points south of Illinois as well as incremental product supply capacity to mid-continent markets downstream of southern Illinois. Marathon operates the mainline Centennial pipeline, and TE Products operates the Beaumont origination point and the Creal Springs terminal.
Through December 31, 2008, including the amount paid for the acquisition of an additional ownership interest in February 2003, TE Products has invested $118.4 million in Centennial. TE Products has not received any distributions from Centennial since its formation.
The mix of products delivered by our Downstream Segment varies seasonally. We generally realize higher revenues in the Downstream Segment during the first and fourth quarters of each year since LPG volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating, and due to the demand for normal butane, which is used for blending of gasoline. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasoline during the spring and summer driving seasons, although recent high gasoline prices have moderated this trend to a certain extent. Weather and economic conditions in the geographic areas served by our Products Pipeline System also affect the demand for, and the mix of, the products delivered.
Major Business Sector Markets and Related Factors
Our Products Pipeline System transports refined products from the upper Texas Gulf Coast, eastern Texas and southern Arkansas to the Central and Midwest regions of the United States with deliveries in Texas, Louisiana, Arkansas, Missouri, Illinois, Kentucky, Indiana and Ohio. At these points, refined products are delivered to terminals owned by TE Products, connecting pipelines and customer-owned terminals.
Our Products Pipeline System transports LPGs from the upper Texas Gulf Coast to the Central, Midwest and Northeast regions of the United States and is the only pipeline that transports LPGs from the upper Texas Gulf Coast to the Northeast. The Products Pipeline System east of our Todhunter facility near Middleton, Ohio, is devoted solely to the transportation of LPGs. Our Products Pipeline System also transports normal butane and isobutane in the Midwest and Northeast for use in the production of motor gasoline.
TTMC conducts distribution and marketing operations whereby we provide terminaling services for our throughput partner at our Aberdeen and Boligee terminals. We also purchase refined products from our throughput partner and establish a margin by selling refined products for physical delivery through spot sales and contract sales. These marketing activities are conducted at our Aberdeen and Boligee truck racks to independent wholesalers and retailers of refined products. Spot purchases and sales are generally contracted to occur on the same day.
For further discussion of refined products and LPGs sensitivity to market conditions and other factors that may affect our Downstream Segment, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “– Overview of Business.”
Our major operations in the Downstream Segment consist of the transportation, storage and terminaling of refined products and LPGs along our system. Product deliveries, in MMBbls on a regional basis, for the years ended December 31, 2008, 2007 and 2006, were as follows:
Our customers for the transportation of refined products include major integrated oil companies, independent oil companies, the airline industry and wholesalers. End markets for these deliveries are primarily retail service stations, truck stops, railroads, agricultural enterprises, refineries and military and commercial jet fuel users. Propane customers include wholesalers and retailers who, in turn, sell to commercial, industrial, agricultural and residential heating customers, utilities who use propane as a back-up fuel source and petrochemical companies who use propane as a process feedstock. Refineries constitute our major customers for butane and isobutane, which are used as a blend stock for gasolines and as a feedstock for alkylation units, respectively. Our customers for the transportation of petrochemical feedstocks (natural gasoline and naphtha) and semi-finished chemical products (RGP, polymer grade propylene and polymer grade ethylene) are primarily major chemical companies that consume these components in the production of plastics and a wide array of other commercial products. TTMC’s customers include major integrated oil companies and wholesale marketers. Our Downstream Segment depends in large part on the level of demand for refined products and LPGs in the geographic locations that we serve and the ability and willingness of customers having access to the pipeline system to supply this demand.
At December 31, 2008, 2007 and 2006, our Downstream Segment had approximately 172, 130 and 125 customers, respectively. During the years ended December 31, 2008, 2007 and 2006, total revenues attributable to the top 10 customers (and percentage of total segment revenues) were $138.1 million (37%), $155.5 million (43%) and $143.5 million (47%), respectively. During each of the three years ended December 31, 2008, 2007 and 2006, no single customer accounted for more than 10% of total Downstream Segment revenues. During each of the three years ended December 31, 2008, 2007 and 2006, no single customer of the Downstream Segment accounted for 10% or more of TEPPCO’s total consolidated revenues.
The Downstream Segment faces competition from numerous sources. Because pipelines are generally the lowest cost method for intermediate and long-haul overland movement of refined products and LPGs, the Products Pipeline System’s most significant competitors (other than indigenous production in its markets) are pipelines in the areas where the Products Pipeline System delivers products. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. We believe our Downstream Segment is competitive with other pipelines serving the same markets; however, comparison of different pipelines is difficult due to varying product mix and operations.
Trucks, barges and railroads competitively deliver products in some of the areas served by the Products Pipeline System and TTMC. Trucking costs, however, render that mode of transportation less competitive for longer hauls or larger volumes. Pipeline systems inherently compete with barge transportation, especially at those locations that are in close proximity to major waterways. We face competition from rail and pipeline movements of LPGs from Canada and waterborne imports into terminals located along the upper East Coast. TTMC’s competition in the area is from refineries that require significant truck transportation to deliver their product in the area TTMC serves. TTMC is able to receive product by barge, which gives it a competitive advantage with respect to other terminaling and marketing businesses in the general area, which generally do not receive product by barge. Further, we view our marine transportation business as a complementary extension of the logistics services that we provide to our existing TTMC customers.
Upstream Segment – Gathering, Transportation, Marketing and Storage of Crude Oil
We conduct business in our Upstream Segment through the following:
Properties and Operations
Our Upstream Segment gathers, transports, markets and stores crude oil, distributes lubrication oils and specialty chemicals and provides fuel transportation services, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Our Upstream Segment uses its asset base to aggregate crude oil and provides transportation and related services to its customers. Our Upstream Segment purchases crude oil from various producers and operators at the wellhead and makes bulk purchases of crude oil on pipelines, terminal facilities and trading locations. The crude oil is purchased under contracts, the majority of which range in term from a thirty-day evergreen to one year. The crude oil is then sold to refiners and other customers. The Upstream Segment transports crude oil through proprietary gathering systems, common carrier pipelines, equity owned pipelines, trucking operations and third party pipelines. The Upstream Segment also exchanges various grades of crude oil and exchanges crude oil at different geographic locations, as appropriate, in order to maximize margins or meet contract delivery requirements. Certain of our crude oil pipeline assets are interstate common carriers, and as such we file tariffs with the FERC. Movement of product on these lines is available to any shipper who requests these services, provided that the conditions and specifications contained in the applicable tariff are satisfied.
The areas served by our gathering and transportation operations are geographically diverse, and the forces that affect the supply of the products gathered and transported vary by region. Crude oil prices and production levels affect the supply of these products. The demand for gathering and transportation is affected by the demand for crude oil by refineries, refinery supply companies and similar customers in the regions served by this business, as well as by production levels in the regions served.
TCO, a significant shipper on TCPL, purchases crude oil and establishes a margin by selling crude oil for physical delivery to third party users. These purchases and sales are generally contracted to occur in the same calendar month. We seek to maintain a balanced marketing position to minimize our exposure to price fluctuations occurring after the initial purchase. However, commodity price risks cannot be completely eliminated. TCO also ships on Seaway, in which we have an ownership interest.
Crude oil deliveries on our 100% owned pipeline systems, Basin and Seaway and deliveries of lubrication oils and specialty chemicals for the years ended December 31, 2008, 2007 and 2006, were as follows (in millions):
The following table describes the major crude oil pipelines and pipeline systems and the ownership percentages in our Upstream Segment as of December 31, 2008:
Most of the Red River System crude oil is delivered via third party pipelines to Cushing, Oklahoma or to two local refineries. The crude oil on the South Texas System is delivered to Houston area refineries and to
Cushing. The West Texas System connects gathering systems to TCPL’s Midland, Texas, terminal which has the ability to deliver crude oil to Cushing.
Seaway Crude Pipeline Equity Investment
Seaway is a partnership between TEPPCO Seaway, L.P. (“TEPPCO Seaway”), a subsidiary of TCTM, and subsidiaries of ConocoPhillips. We operate and commercially manage the Seaway assets. Three large diameter lines carry imported crude oil from the Freeport, Texas, marine terminal on the U.S. Gulf Coast to the adjacent Jones Creek Tank Farm, which has six tanks capable of holding approximately 2.6 million barrels of crude oil. The 30-inch diameter, 500-mile pipeline transports crude oil from Freeport to Cushing, a central crude distribution point for the central United States and a delivery point for the New York Mercantile Exchange (“NYMEX”). Seaway also has a connection to our South Texas system that allows it receive both onshore and offshore domestic crude oil in the Texas Gulf Coast area for delivery to Cushing.
The Seaway crude oil marine terminal facility at Texas City, Texas, supplies refineries in the Houston area. Two pipelines connect the Texas City marine terminal to storage facilities in Texas City and Galena Park, Texas, where there are nine tanks with total capacity of approximately 4.2 million barrels. Seaway is able to provide marine terminaling and crude oil storage services for all Houston area refineries.
The Seaway partnership agreement provides for varying participation ratios throughout the life of Seaway. From June 2002 through December 31, 2005, we received 60% of revenue and expense of Seaway. The sharing ratio changed from 60% to 40% on May 12, 2006, and as such, our share of revenue and expense of Seaway was 47% for 2006. Thereafter, we will receive 40% of revenue and expense (and distributions) of Seaway. During the years ended December 31, 2008, 2007 and 2006, we received distributions from Seaway of $13.8 million, $12.4 million and $20.5 million, respectively.
Texas Offshore Port System Joint Venture
In August 2008, we, together with Enterprise Products Partners and Oiltanking formed Texas Offshore Port System, a joint venture to design, construct, operate and own a new Texas offshore crude oil port and pipeline system to facilitate delivery of waterborne crude oil to refining centers located along the upper Texas Gulf Coast. The joint venture’s primary project, referred to as “TOPS,” includes (i) an offshore port (which will be located approximately 36 miles from Freeport, Texas), (ii) an onshore storage facility with approximately 3.9 million barrels of total crude oil storage capacity, and (iii) an 85-mile pipeline system that will have the capacity to deliver up to 1.8 million barrels per day of crude oil, that will extend from the offshore port to a storage facility near Texas City, Texas. The joint venture’s complementary project, referred to as the Port Arthur Crude Oil Express (“PACE”), will transport crude oil from Texas City, including crude oil from TOPS, and will consist of a 75-mile pipeline and 1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas area. Development of the TOPS and PACE projects is supported by long-term contracts with affiliates of Motiva and Exxon Mobil Corporation, which have committed a combined 725,000 barrels per day of crude oil to the projects. The timing of the construction and related capital costs of the TOPS and PACE projects will be affected by the acquisition of requisite permits.
We, Enterprise Products Partners and Oiltanking each own, through our respective subsidiaries, a one-third interest in the joint venture. A subsidiary of Enterprise Products Partners acts as construction manager and will act as operator. The aggregate cost of the TOPS and PACE projects is expected to be approximately $1.8 billion (excluding capitalized interest), with the majority of such capital expenditures currently expected to occur in 2010 and 2011. We and an affiliate of Enterprise Products Partners have each guaranteed up to approximately $700.0 million, which includes a contingency amount for potential cost overruns, of the capital contribution obligations of our respective subsidiary partners in the joint venture. At December 31, 2008, we have invested $36.0 million in this joint venture.
The joint venture is part of our strategic plan for growing the Partnership. Demand for the project is being driven by planned and expected refinery expansions along the U.S. Gulf Coast, expected increased shipping traffic and operating limitations of regional ship channels. Further, the joint venture complements our 5.4 million barrel refined products storage facility currently under construction in Port Arthur to support the expansion of Motiva’s nearby refinery, which is expected to double its existing capacity in 2010.
Line Transfers, Pumpovers and Other
Our Upstream Segment provides trade documentation services to its customers, primarily at Cushing and Midland. TCPL documents the transfer of crude oil in its terminal facilities between contracting buyers and sellers. This line transfer documentation service is related to the trading activity by TCPL’s customers of NYMEX crude oil contracts and other physical trading activity. This service provides a record of receipts, deliveries and transactions to each customer, including confirmation of trade matches, inventory management and scheduled movements.
The line transfer services also attract physical barrels to TCPL’s facilities for final delivery. A pumpover occurs when the last title transfer is executed and the physical barrels are delivered out of TCPL’s custody to the ultimate owner. TCPL owns and operates storage facilities primarily in Midland and Cushing with a storage capacity of approximately 4.1 million barrels to facilitate the terminaling business.
LSI distributes lubrication oils and specialty chemicals to natural gas pipelines, gas processors and industrial and commercial accounts and provides fuel transportation services. LSI’s distribution networks are located in Colorado, Wyoming, Oklahoma, Kansas, New Mexico, Texas and Louisiana.
On August 1, 2008, we purchased lubrication and other fuel oil assets, located in Wyoming, from Quality Petroleum, Inc. for approximately $6.8 million, which includes $1.3 million related to a non-compete agreement. The assets, included in our Upstream Segment, consist of operating inventory, buildings, land and various equipment and the assignment of certain distributor agreements. Through its subsidiary, QP-LS, LLC, LSI provides fuel transportation services to customers.
Our customers for the sale, transportation, storage and terminaling of crude oil include major integrated oil companies, independent refiners and marketers. LSI distributes lubrication oils and specialty chemicals to natural gas pipelines, gas processors and industrial and commercial accounts, with networks located in Colorado, Wyoming, Oklahoma, Kansas, New Mexico, Texas and Louisiana. LSI also provides fuel transportation services to customers primarily in Wyoming.
Gross sales revenue of the Upstream Segment attributable to the top 10 customers (and percentage of total segment gross sales revenue) was $13.0 billion (96%), $8.1 billion (84%) and $7.4 billion (75%) for the years ended December 31, 2008, 2007 and 2006, respectively. For the year ended December 31, 2008, Valero Energy Corp. (“Valero”), BP Oil Supply Company and Shell Trading Company accounted for 22%, 17% and 14%, respectively, of the Upstream Segment gross sales revenue. For the year ended December 31, 2007, Valero, BP Oil Supply Company and Shell Trading Company accounted for 17%, 15% and 12%, respectively, of the Upstream Segment gross sales revenue. For the year ended December 31, 2006, Valero and BP Oil Supply Company accounted for 15% and 12%, respectively, of the Upstream Segment gross sales revenue.
For the year ended December 31, 2008, Valero, BP Oil Supply Company and Shell Trading Company accounted for 21%, 16%, and 13%, respectively, of TEPPCO’s total consolidated revenues. For the year ended December 31, 2007, Valero, BP Oil Supply Company and Shell Trading Company accounted for 16%, 14% and 12%, respectively, of TEPPCO’s total consolidated revenues. For the year ended December 31, 2006, Valero and BP Oil Supply Company accounted for 14% and 11%, respectively, of TEPPCO’s total consolidated revenues.
The Upstream Segment faces competition from numerous sources. The most significant competitors in pipeline operations in our Upstream Segment are primarily common carrier and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where our pipeline systems receive and deliver crude oil. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service, knowledge of products and markets, and proximity to refineries and connecting pipelines.
The crude oil gathering and marketing business can be characterized by thin margins and strong competition for supplies of crude oil at the wellhead, and declines in domestic crude oil production have intensified this competition. The most significant competitors in the crude oil gathering and marketing business include other crude oil pipeline companies, major integrated oil companies and their marketing affiliates, financial institutions with trading platforms and independent gatherers and marketers. Competition is based primarily on quality of customer service, competitive pricing and proximity to refiners and other marketing hubs.
Midstream Segment – Gathering of Natural Gas, Transportation of NGLs and Fractionation of NGLs
We conduct business in our Midstream Segment through the following:
Properties and Operations
Our Midstream Segment gathers natural gas, transports NGLs and fractionates NGLs. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances settled in-kind and the purchase and sale of natural gas by Jonah to facilitate system operations and to provide a service to some of the producers on the system.
Volume information for the years ended December 31, 2008, 2007 and 2006, is presented below:
Jonah Gas Gathering Joint Venture
The majority of the growth in the Midstream Segment is due to our expansions of the Jonah system, which is located in the Green River Basin in southwestern Wyoming. Since our acquisition of Jonah in 2001, the system has been expanded in five phases, increasing system capacity from approximately 450 MMcf/d to approximately 2.35 Bcf per day.
In August 2006, Enterprise Products Partners, through its affiliate, Enterprise Gas Processing, LLC, became our joint venture partner by acquiring an interest in Jonah, the partnership through which we have owned our interest in the system serving the Jonah and Pinedale fields. Enterprise Products Partners serves as operator of Jonah. The joint venture is governed by a management committee comprised of two representatives approved by Enterprise Products Partners and two representatives approved by us, each with equal voting power. The formation of the joint venture was reviewed and recommended for approval by the Audit, Conflicts and Governance Committee of the Board of Directors of our General Partner (“ACG Committee”).
In February 2006, Enterprise Products Partners assumed management of the Jonah Phase V expansion project and funded the initial costs of the expansion. Beginning with the August 1, 2006 formation of the Jonah joint venture, we reimbursed Enterprise Products Partners for 50% of the expansion cost previously advanced. From August 1, 2006 through July 2007, we and Enterprise Products Partners equally shared the costs of the Phase V expansion, and Enterprise Products Partners shared in the incremental cash flow and distributions resulting from the operation of those new facilities. During August 2007, with the completion of the first portion of the expansion, we and Enterprise Products Partners began sharing joint venture cash distributions and earnings based on a formula that takes into account the capital contributions of the parties, including expenditures by us prior to the expansion. Based on this formula in the partnership agreement, beginning in August 2007, our ownership interest in Jonah was approximately 80.64%, and Enterprise Products Partners’ ownership interest in Jonah was approximately 19.36%. Amounts exceeding an agreed upon base cost estimate for the expansion of $415.2 million were shared 19.36% by Enterprise Products Partners and 80.64% by us. Our ownership interest in Jonah is currently anticipated to remain at 80.64%.
In early 2008, Jonah began an expansion of the portion of its system serving the Pinedale field, which is expected to increase the combined capacity of the system serving the Jonah and Pinedale fields from 2.35 Bcf per day to approximately 2.55 Bcf per day. This project will include an additional 17,000 horsepower of compression at the Paradise and Bird Canyon stations in Sublette County, Wyoming and involve construction of approximately 52 miles of 30-inch and 24-inch diameter pipelines. The pipelines and 10,200 horsepower of compression were completed and placed in service in November 2008. The remaining 6,800 horsepower of compression at Bird Canyon is expected to be completed in mid 2009. The total anticipated cost of this system expansion is expected to be approximately $125.0 million. Our share of the costs of the construction is expected to be 80.64%, and Enterprise Products Partners’ share is expected to be 19.36%. Enterprise Products Partners is managing this construction project.
Jonah Gas Gathering System Business. The Jonah system serves the Jonah and Pinedale fields in Wyoming, which, according to the Energy Information Administration’s (“EIA”) 2006 estimates, were among the top ten natural gas producing fields in the United States. The system delivers natural gas to pipelines and gas processing facilities owned by others. From the processing facilities, the natural gas is delivered into several interstate pipeline systems located in the region for transportation to end-use markets throughout the Midwest, the West Coast and the Rocky Mountain regions. Interstate pipelines in the region include Kern River, Northwest, Colorado Interstate Gas, Questar’s mainline pipeline and access to the Rockies Express Pipeline via Questar Overthrust. At the end of 2008, the Jonah system consists of approximately 714 miles of pipelines ranging in size from three inches to 36 inches in diameter, five compressor stations with an aggregate of approximately 273,800 horsepower and related metering facilities. Gas gathered on the Jonah system is collected from approximately 2,021 producing wells in southwestern Wyoming’s Green River Basin.
In addition to gathering natural gas, Jonah also purchases gas at the wellhead and sells gas and condensate. The Jonah system sells condensate liquid from the natural gas stream to TCO. The sales price is contractually based on a crude oil index price less a differential. In May 2006, we began to purchase gas at the wellhead on Jonah and re-sell the aggregated quantities at key Jonah delivery points in order to facilitate Jonah’s operations. The purchases and sales generally occur within the same month to minimize price risk.
Jonah has fee-based gathering agreements with fees that increase as field pressures decrease. Approximately 18 producers are connected to the system, of which seven have life-of-lease contracts. The four top producers are under life-of-lease contracts that represent approximately 96% of the volumes of the system in 2008. Under these agreements, Jonah gathers and compresses the natural gas supplied to its gathering system and then redelivers the natural gas to gas processing facilities and interstate pipelines located in the region for a fee. Jonah does not generally take title to the natural gas gathered with the exception of inventory imbalances settled in-kind and the purchase and sale of natural gas to facilitate system operations and to provide a service to some of the producers on the system. Other than the effects of normal operating pressure fluctuations, we can neither influence nor control the operation, development or production levels of the gas fields served by the Jonah system, which may be affected by price and price volatility, market demand, depletion rates of existing wells and changes in laws and regulations.
Val Verde Gas Gathering System
The Val Verde system consists of approximately 400 miles of pipeline ranging in size from four inches to 36 inches in diameter, 14 compressor stations operating over 75,000 horsepower of compression and an amine treating facility. The Val Verde gathering system is capable of gathering and treating approximately 550 million cubic feet of gas per day. The Val Verde system delivers gas to El Paso Natural Gas Company and Transwestern Pipeline Company, two interstate pipeline systems serving the western United States.
The Val Verde system gathers coal bed methane (“CBM”) from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado and some conventional natural gas for the producers. The system gathers natural gas from more than 500 separate wells throughout northern New Mexico and southern Colorado. Gathering and treating services are provided pursuant to long-term fixed-fee contracts with approximately 40 natural gas producers in the San Juan Basin. These contracts are generally long-term commitments, with evergreen clauses, the majority of which have gathering rates that escalate annually. Under these contracts, Val Verde gathers the natural gas supplied to its gathering systems, treats the natural gas to meet pipeline specifications and redelivers the natural gas for a fixed fee. Val Verde does not take title to the natural gas. CBM volumes gathered on the Val Verde system have been in decline, and are expected to continue to decline, primarily due to the natural decline of CBM production and the maturity of the field. Other than the effects of normal operating pressure fluctuations, we can neither influence nor control the operation, development or production levels of the gas fields served by the Val Verde system, which may be affected by price and price volatility, market demand, depletion rates of existing wells and changes in laws and regulations.
In December 2004, we completed a 16-mile project to connect Val Verde with a third party gathering system originating in Colorado and entered into a multi-year agreement to transport and treat natural gas through this connection. Val Verde transported an average of 155 MMcf/d from this interconnection in 2008.
NGL Transportation and Fractionation
The NGL pipelines of the Midstream Segment are located along the Texas Gulf Coast, in East Texas and from southeastern New Mexico and West Texas to Mont Belvieu. They are all wholly owned and operated by our subsidiaries. Information about these NGL pipelines as of December 31, 2008, is set forth in the following table:
Chaparral Open Season. In February 2008, Chaparral announced the start of a binding “open season” process to seek shipper support for a proposed expansion of its pipeline. The open season was successfully concluded in June 2008 with the commitment from shippers for a 15-year term at a transportation rate that we believe is sufficient to justify the capital expenditures necessary to expand the Chaparral pipeline capacity. The project is designed to increase annual average system capacity by approximately 15,000 barrels per day. The expansion, which is anticipated to cost approximately $10.0 million and to be completed in the second half of 2009, involves upgrading certain pipe sections, and includes installing additional pumping capability at existing pump stations.
Fractionation. TEPPCO Colorado has two NGL fractionation facilities, located in northeast Colorado, which separate NGLs into individual components. TEPPCO Colorado is currently supported by a fractionation agreement with DCP Midstream Partners, L.P. (“DCP”) through 2018. Based upon contract terms, fractionation revenues are recognized based upon the volume of NGLs fractionated at a fixed rate per gallon. Under an operation and maintenance agreement, DCP also operates and maintains the fractionation facilities for TEPPCO Colorado. For these services, TEPPCO Colorado pays DCP a set volumetric rate for all fractionated volumes delivered to DCP.
Typically, our natural gas gathering systems experience higher throughput rates during the summer months, when natural gas-fired power generation facilities increase output to meet residential and commercial demand for electricity for air conditioning and in the winter months, when natural gas is needed as fuel for residential and commercial heating. Additionally, at Jonah, new well connections have historically been subject to seasonal constraints as a result of winter range restrictions in the Pinedale field. Producers in the Pinedale field were prohibited from drilling activities typically during November through April due to wildlife restrictions, and accordingly we were limited in our ability to connect new wells to the system during that time. During 2008, the majority of these restrictions were lifted, and as such, the producers in the Pinedale field have fewer drilling restrictions.
The Midstream Segment’s customers for natural gas gathering include major integrated oil and gas companies and large to medium-sized independent producers. Natural gas from Jonah and Val Verde is delivered into major interstate gas pipelines for delivery primarily to markets in the western and mid-continent areas of the United States. The Midstream Segment’s customers for transporting NGLs include affiliates of EPCO and other major integrated oil and gas companies.
At December 31, 2008, the Midstream Segment had approximately 58 customers. Revenue attributable to the top 10 customers (and percentage of total segment revenues) was $105.8 million (86%) for the year ended December 31, 2008, of which DCP and its affiliates, ConocoPhillips (and its subsidiary, Burlington Resources Inc.), and Enterprise Products Partners and its affiliates accounted for approximately 20%, 20% and 11%, respectively.
At December 31, 2007, the Midstream Segment had approximately 52 customers. Revenue attributable to the top 10 customers (and percentage of total segment revenues) was $105.8 million (87%) for the year ended December 31, 2007, of which ConocoPhillips (and its subsidiary, Burlington Resources Inc.), DCP and its affiliates, and Enterprise Products Partners and its affiliates accounted for approximately 22%, 20% and 11%, respectively.
At December 31, 2006, the Midstream Segment had approximately 65 customers. Revenue attributable to the top 10 customers (and percentage of total segment revenues) was $163.4 million (79%) for the year ended December 31, 2006, of which EnCana Corporation, ConocoPhillips (and its subsidiary, Burlington Resources Inc.), DCP and its affiliates and BP Energy accounted for approximately 15%, 14%, 12% and 12%, respectively.
During each of the three years ended December 31, 2008, 2007 and 2006, no single customer of the Midstream Segment accounted for 10% or more of TEPPCO’s total consolidated revenues.
Competition in the natural gas gathering operations of our Midstream Segment is based largely on reputation, efficiency, system reliability, system capacity and price arrangements. Key competitors in the gathering and treating segment include independent gas gatherers as well as other major integrated energy companies. Alternate gathering facilities may be available to producers served by our Midstream Segment, and those producers could also elect to construct proprietary gas gathering systems. Success in the gas gathering and treating business segment is based primarily on a thorough understanding of the needs of the producers served, a strong commitment to providing responsive, high-quality customer service, as well as proximity to new drilling and development.
The Midstream Segment’s NGL pipeline operations face competition from other competing pipelines. The most significant competition for the NGL pipeline operations of our Midstream Segment comes from pipelines owned and operated by major oil and gas companies and other large independent pipeline companies with facilities that are in or near our operational areas. The ability to compete in the NGL pipeline area is based primarily on competitive fees, the quality of customer service and knowledge of products and markets.
Marine Services Segment – Barge Transportation of Petroleum Products
We conduct business in our Marine Services Segment through TEPPCO Marine Services, which:
We entered the marine transportation business on February 1, 2008 when we acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements that comprised the marine transportation business of Cenac Towing Co., Inc. (“Cenac Towing”), Cenac Offshore, L.L.C. and Mr. Arlen B. Cenac, Jr., the sole owner of Cenac Towing Co., Inc. and Cenac Offshore, L.L.C. (collectively, “Cenac”). On February 29, 2008, we expanded our Marine Services Segment with the acquisition of marine assets from Horizon Maritime, L.L.C. (“Horizon”), a privately-held Houston-based company and an affiliate of Mr. Cenac. We acquired 7 tow boats, 17 tank barges, rights to two tow boats under construction and certain related commercial and other agreements (or the associated economic benefits). One of the tow boats under construction was delivered to us in April 2008 and the second in June 2008.
In connection with our entry in the marine transportation business, we entered into a transitional operating agreement with Cenac for a period of up to two years from the date of the Cenac acquisition. Cenac operates our Marine Services Segment through their marine and shore-based support employees. Under the transitional operating agreement, we reimburse Cenac for personnel salaries and related employee benefit expenses and certain repairs and maintenance expenses on our equipment, as well as payment of a monthly service fee.
Properties and Operations
The United States inland waterway system is a vast and extensively utilized transportation system, consisting of a network of interconnected rivers and canals that serve as water highways upon which vast quantities of products are transported annually. The inland waterway system includes approximately 12,000 miles of waterways that are generally considered navigable. Barge transportation is more fuel efficient and produces fewer emissions than similar movements by truck or rail and also reduces road and rail congestion. The capacity of one barge is equivalent to 15 railcars or 60 trucks; one gallon of fuel moves one ton of cargo 576 miles on the inland waterways, 413 miles on rail, and 155 miles on truck; and barge transportation produces 40% less air emissions than truck and 16% less air emission than rail for cargo movements (ton-miles).
The marine transportation industry uses tow boats as power sources and tank barges for freight capacity. The combination of the power source and barge freight capacity is called a tow. Our inland tows generally consist of one push boat and from one to four barges, depending upon the horsepower of the push boat, the trading territory, waterway conditions, customer requirements and prudent operations. Our offshore tows generally consist of one tugboat and one ocean-certified tank barge.
The following is a summary description of the marine vessels we use, as of December 31, 2008, in our marine transportation business and certain operating statistics for the Marine Services Segment:
Our transportation services are generally provided under term contracts (also referred to as affreightment contracts), which are agreements with specific customers to transport cargo from within designated operating areas at set day rates or a set fee per cargo movement. Most of the inland term contracts have one-year terms with the remainder having terms of up to two years. Substantially all of the inland contracts have renewal options, which are exercisable subject to agreement on rates applicable to the option terms. Most of the offshore service and transportation contracts have up to one-year terms with renewal options, which are exercisable subject to agreement on rates applicable to the option terms, or are spot contracts. A spot contract is an agreement with a customer to move cargo within designated operating areas for a rate negotiated at the time the cargo movement takes place.
As is typical for inland and offshore affreightment contracts, the term contracts establish set day rates but do not include revenue or volume guarantees. Most of the contracts include escalation provisions to recover specific increased operating costs such as incremental increases in labor. The costs of fuel, substantially all of which is a passthrough expense, and other specified operational fees and costs are directly reimbursed by the customer under most of the contracts. We are responsible for the remaining operating costs, including equipment maintenance costs, various inspection costs, the cost of maintaining insurance coverage on the vessels under these contracts, and other operating costs under certain of our contracts that do not contain such reimbursement or escalation provisions. We do not assume ownership of the products we transport in this segment.
Since our acquisition of Cenac and Horizon through the end of the third quarter of 2008, as the customer contracts became subject to periodic renewal, we obtained renewals of substantially all contracts at increased day rates. During the fourth quarter of 2008, there were five inland customer affreightment contracts that were not
renewed due to general economic conditions. The marine vessels impacted by these non-renewals will be employed in the spot market until we can secure term contracts. As a result, our fleet utilization may be reduced during 2009 compared to 2008 levels. As overall demand for refined products has declined some softening of the transportation market is expected. Additionally, as the customer contracts become subject to periodic renewal during 2009, we expect to renew them at day rates generally consistent with the current economic refined products and crude oil market dynamics.
Our marine transportation business is subject to regulation by the U.S. Department of Transportation, Department of Homeland Security, Commerce Department and the U.S. Coast Guard (“USCG”) and federal and state laws. Substantially all of our inland barges are inspected by the USCG and carry certificates of inspection. Our inland and offshore towing vessels are not currently subject to USCG inspection requirements; however, regulations are currently proposed that would subject inland and offshore towing vessels to USCG inspection requirements. Most of our offshore towing vessels and barges are built in compliance with American Bureau of Shipping (“ABS”) Load Line standards and are inspected periodically by ABS to maintain this standard. The crews employed by Cenac aboard vessels, including captains, pilots, engineers, tankermen, deckhands and ordinary seamen, are all licensed by the USCG with the exception of engineers and deckhands on certain inland vessels. We or Cenac, as operator, are required by various governmental agencies to obtain licenses, certificates and permits for our vessels depending upon such factors as the cargo transported, the waters in which the vessels operate and other factors.
Cenac and TEPPCO Marine Services belong to the American Waterways Operators (“AWO”) Responsible Carrier Program (“RCP”). The program provides a framework of safety standards and best practices designed to continuously enhance member companies’ safety and efficiency in the operation of inland marine vessels. The program complements and builds upon existing government regulations, requiring company safety and training standards that in many instances exceed those required by federal law or regulation. Many of our contracts contain provisions regarding AWO membership and RCP compliance. The RCP has been recognized by many groups, including the USCG and shipper organizations. We are periodically audited by an AWO-certified auditor to verify compliance.
EPCO maintains insurance coverage on marine operations on our behalf, although insurance will not cover many types of hazards that might occur, including certain environmental accidents, and if covered we may still have responsibility for any applicable deductibles. Our marine insurance program covers our hulls and certain liabilities which may arise from vessel operations.
Cenac maintains an experienced work force of marine and shore-based personnel. As of December 31, 2008, approximately 451 of Cenac’s employees provide services to TEPPCO Marine Services under the transitional operating agreement. Cenac’s tow and barge captains are non-union management supervisors. Its marine employees are paid on a daily basis, and the majority work 14 days on and 7 days off. Cenac’s shore-based personnel are generally salaried and most are located at its headquarters in Houma, Louisiana.
Cenac’s shore-based staff provides support for all aspects of our fleet and business operations, including sales and scheduling, crewing and human resources functions, engineering, compliance and technical management, financial services and information technology. A staff of dispatchers and schedulers maintain a 24-hour duty rotation to monitor communications and to coordinate fleet operations with our customers and terminals. Communication with our vessels is accomplished by various methods, including wireless data links, cellular telephone, VHF and radio and satellite telephone.
Under the transitional operating agreement, Cenac is responsible for maintaining our vessels in seaworthy and good working condition and operating our vessels in accordance with applicable laws and prudent industry practices. Cenac’s trained crews regularly inspect each vessel, both at sea and in port, and perform all routine preventive maintenance. Staff conduct quarterly inspections regarding overall condition, maintenance, safety and crew welfare, and selected vessels are inspected annually by third party consultants.
We expect that overall increased demand for refined products such as motor fuels during the spring and summer driving seasons will result in increased demand for our marine transportation services during those seasons. Demand for asphalt is generally seasonal, with higher volumes typically transported during months when weather allows for efficient road construction. Weather events, such as hurricanes and tropical storms entering in the U.S. Gulf of Mexico, can adversely impact both the offshore and inland businesses. Cold weather and ice can negatively impact the inland operations on the upper Mississippi and Illinois rivers. Our offshore marine vessels support pipeline cleanout operations which typically are performed during the summer months.
Our largest marine transportation customers include major and independent oil companies, crude oil producers, traders and refiners. We provide towing services primarily for major oil companies in the refining industry in the states along the U.S. Gulf Coast.
At December 31, 2008, our Marine Services Segment had approximately 42 customers. Revenues attributable to the top 10 customers (and percentage of total segment revenues) was $130.9 million (80%) for the year ended December 31, 2008, of which Valero, Plains Marketing L.P. and Shell and affiliates accounted for 28%, 16% and 13%, respectively. During the year ended December 31, 2008, no single customer of the Marine Services Segment accounted for more than 10% of TEPPCO’s total consolidated revenues.
Our marine transportation business competes with inland marine transportation companies as well as providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines. While competition within the marine transportation business is based largely on price, we believe that the decline in the past two decades in the number of inland barges operating in the inland U.S. waterways, consolidation in the marine transportation industry and barriers to entry in the industry, such as cost and ability to obtain licensed and qualified personnel, have resulted in a favorable pricing environment for our marine transportation business. We also believe that our ability to offer alternative means of transportation, for example, via our Products Pipeline System, positions us well to compete against pipelines and marine transportation companies that service the areas in which our marine transportation business operates. We believe we can offer a competitive advantage over rail tank cars and tractor-trailer tank trucks because, by volume, marine transportation is a substantially more efficient, and generally less expensive, mode of transporting petroleum products and by-products. For example, one of our typical two inland barge unit tows carry a volume of product equal to approximately 69 rail cars or 278 tanker trucks.
We also believe we can offer a competitive advantage over our competitors due to the lower age of our fleet of marine vessels compared to the industry average. The average age of our fleet is 12 years versus an industry average of 22 years. However, several of our competitors have announced their intention to increase their tank barge fleets. We currently believe demand within the inland marine transportation industry will absorb the additional capacity being built, but additional new construction could create an oversupply of capacity within the industry.
Title to Properties
We believe we have satisfactory title to all of our assets. The properties are subject to liabilities in certain cases, such as contractual interests associated with acquisition of the properties, liens for taxes not yet due, easements, restrictions and other minor encumbrances. We believe none of these liabilities materially affect the value of our properties or our interest in the properties or will materially interfere with their use in the operation of our business.
Capital expenditures, excluding acquisitions and contributions to joint ventures, totaled $300.5 million for the year ended December 31, 2008. Revenue generating projects include those projects which expand service into new markets or expand capacity into current markets. Capital expenditures to sustain existing operations include projects required by regulatory agencies or required life-cycle replacements. System upgrade projects improve operational efficiencies or reduce cost. We capitalize interest costs incurred during the period that construction is in progress. The following table identifies capital expenditures by segment for the year ended December 31, 2008 (in millions):
Revenue generating capital spending by the Downstream Segment totaled $162.6 million and was used primarily for the construction of a new refined products storage facility to support the expansion of Motiva’s refinery in Port Arthur, Texas, construction of a new terminal in Boligee, Alabama, the continued integration of assets from an acquisition in 2005 and expansion of delivery capability into Memphis, Tennessee. Revenue generating capital spending by the Midstream Segment totaled $1.2 million and was used primarily to increase capacity of the Panola Pipeline. Revenue generating capital spending by the Upstream Segment totaled $11.5 million and was used primarily for the expansion of our facilities and pipeline connections in West Texas and Cushing, Oklahoma. Revenue generating capital spending by the Marine Services Segment totaled $42.4 million and was used primarily for the construction and acquisition of additional tow boats and tank barges. In order to sustain existing operations, we spent $29.0 million for various Downstream Segment pipeline projects, $3.5 million for the Midstream Segment, $17.2 million for Upstream Segment facilities, $0.6 million for the Marine Services Segment and $8.2 million for our allocated share of EPCO spending related to various assets, including vehicles, computer equipment and software that benefit all of our business segments. An additional $10.9 million was spent on system upgrade projects among all of our business segments.
We estimate that capital expenditures, excluding acquisitions and joint venture contributions, for 2009 will be approximately $340.0 million (including approximately $17.0 million of capitalized interest). Excluding capitalized interest, we expect to spend approximately $270.0 million for revenue generating projects, which includes $170.0 million for our expected spending on the Motiva project. We expect to spend approximately $49.0 million to sustain existing operations (including $16.0 million for pipeline integrity) including life-cycle replacements for equipment at various facilities and pipeline and tank replacements among all of our business segments. We expect to spend approximately $4.0 million to improve operational efficiencies and reduce costs among all of our business segments.
Additionally, we expect to invest approximately $27.0 million in our Jonah joint venture during 2009 for the completion of additional facilities to expand the Pinedale field production. We invested approximately $129.8 million in our Jonah joint venture during 2008. We expect to invest approximately $70.0 million in 2009 as our net contribution to our Texas Offshore Port System joint venture. We invested approximately $36.0 million during 2008 in our Texas Offshore Port System joint venture.
During 2009, TE Products may be required to contribute cash to Centennial to cover capital expenditures, debt service requirements or other operating needs. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business operations. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through
internally generated funds, joint venture distributions, debt or the issuance of additional equity, and the possible disposition of assets.
Certain of our crude oil, petroleum products and natural gas liquids pipeline systems (“liquids pipelines”) are interstate common carrier pipelines subject to rate regulation by the FERC, under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (“Energy Policy Act”). The ICA prescribes that interstate tariffs must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with the FERC and posted publicly.
The ICA permits interested persons to challenge proposed new or changed rates or rules and authorizes the FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it may require the carrier to refund the revenues in excess of the prior tariff during the term of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates and rules that are already in effect and may order a carrier to change them prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of its complaint.
The Energy Policy Act deems just and reasonable (i.e., “grandfathered”) liquids pipeline rates that were in effect for the twelve months preceding enactment and that had not been subject to complaint, protest or investigation. The Energy Policy Act also limits the circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party must show that it was previously contractually barred from challenging the rates, or that the economic circumstances of the liquids pipeline that were a basis for the rate or the nature of the service underlying the rate had substantially changed or that the rate is unduly discriminatory or preferential. Some, but not all, of our interstate liquids pipeline rates are considered grandfathered under the Energy Policy Act. FERC has interpreted the Energy Policy Act to require a demonstration of a substantial change in the overall rate of return of a pipeline, not simply a single cost element, in order for a “grandfathered” rate to no longer be deemed just and reasonable. The U.S Court of Appeals for the D.C. Circuit upheld this interpretation in 2007.
Certain other rates for our interstate liquids pipeline services are charged pursuant to a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the change from year to year in the Producer Price Index for finished goods (“PPI”). A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s costs. Effective March 21, 2006, FERC issued its final order concluding its second five-year review of the oil pipeline pricing index. FERC concluded that for the five-year period commencing July 1, 2006, liquids pipelines charging indexed rates may adjust their indexed ceilings annually by the PPI plus 1.3 percent (“PPI Index”). At the end of that five year period, in July 2011, the FERC will once again review the PPI Index to determine whether it continues to measure adequately the cost changes in the oil pipeline industry.
As an alternative to using the PPI Index, interstate liquids pipelines may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements with all of the pipeline’s shippers that the rate is acceptable. TE Products has been granted permission by the FERC to utilize Market-Based Rates for all of its refined products movements other than the Little Rock, Arkansas, Arcadia and Shreveport-Arcadia, Louisiana destination markets, which are currently subject to the PPI Index. As with all rates for service on an oil pipeline subject to FERC regulation under the ICA, TE Products must file its Market-Based Rates with FERC and charge those rates on a non-discriminatory basis, such that the same Market-Based Rate shall be charged to similarly situated shippers. With respect to LPG movements, TE Products uses the PPI Index. All interstate transportation movements of crude oil by TCPL are subject to the PPI Index as are the NGL interstate transportation movements on the Chaparral NGL system.
Because of the complexity of ratemaking, the lawfulness of any rate is never assured. The FERC uses prescribed rate methodologies for approving regulated tariff rates for transporting crude oil and refined products. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs. Changes in the FERC’s approved methodology for approving rates could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow. Challenges to our tariff rates could be filed with the FERC. We believe the transportation rates currently charged by our interstate common carrier pipelines are in accordance with the ICA. However, we cannot predict the rates we will be allowed to charge in the future for transportation services by our interstate liquids pipelines.
Currently, none of our tariffs are calculated using cost of service rate methodologies. If, however, in the future our tariffs are calculated using a cost of service rate methodology, our revenues might be adversely affected by changes in the FERC’s ratemaking policies.
In May 2005, the FERC issued a “Policy Statement on Income Tax Allowances” (“Policy Statement”), which addressed the circumstances in which a partnership or other pass-through entity would be permitted to include a tax allowance in its cost of service. In December 2005, the FERC issued its “Order on Initial Decision and on Certain Remanded Cost Issues” in various dockets involving another pipeline (the “December 2005 Order”). Among other things, the December 2005 Order applied the Policy Statement to the specific facts of a case involving another pipeline, suggesting how the FERC will treat other Master Limited Partnership (“MLP”) petroleum pipelines. The December 2005 Order confirmed that an MLP is entitled to a tax allowance with respect to partnership income for which there is an “actual or potential income tax liability” and determined that a unitholder that is required to file a Form 1040 or Form 1120 tax return that includes partnership income or loss is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. The FERC also established certain other presumptions, including that corporate unitholders are presumed to be taxed at the maximum corporate tax rate of 35% while individual unitholders (and certain other types of unitholders taxed like individuals) are presumed to be taxed at a 28% tax rate. The D.C. Circuit Court of Appeals fully upheld FERC’s new tax allowance policy and the application of that policy in the December 2005 Order.
In April 2008, the FERC issued a Policy Statement in which it declared that it would permit MLPs to be included in rate of return proxy groups for determining rates for services by natural gas and oil pipelines. It also addressed the application to limited partnership pipelines of the FERC’s discounted cash flow methodology for determining rates of return on equity. The FERC applied the new policy to several ongoing proceedings involving other pipelines. The FERC’s income tax allowance and rate of return policies remain subject to change.
The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that affect the rates we charge and terms and conditions of that service. Although state regulation typically is less onerous than FERC regulation, proposed and existing rates subject to state regulation and the provision of non-discriminatory service are subject to challenge by complaint.
The Val Verde and Jonah natural gas gathering systems are exempt from FERC regulation under the Natural Gas Act of 1938 since they are intrastate gas gathering systems rather than interstate transmission pipelines. However, FERC regulation still significantly affects the Midstream Segment, directly or indirectly, by its influences on the parties that produce the natural gas gathered on the Val Verde and Jonah systems as well as the parties that transport that natural gas. In addition, in recent years, the FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue the pro-competition policies as it considers pipeline rate case proposals, revisions to rules and policies that affect shipper rights of access to interstate natural gas transportation capacity or proposals by natural gas pipelines to allow natural gas pipelines to charge negotiated rates without rate ceiling limits, such policy changes could have an adverse effect on the gathering rates the Midstream Segment is able to charge in the future.
Environmental and Safety Matters
Our pipelines and other facilities are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations. These include, without limitation: the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Clean Air Act; the Federal Water Pollution Control Act or the Clean Water Act; the Oil Pollution
Act; and analogous state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations. If an accidental leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination. Any or all of this could materially affect our results of operations and cash flows.
The following is a discussion of all material environmental and safety laws and regulations that relate to our operations. We believe that we are in material compliance with all these environmental and safety laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial position. We cannot ensure, however, that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (“CWA”), and comparable state laws impose strict controls against the discharge of oil and its derivatives into navigable waters. The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing petroleum or other hazardous substances. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives in navigable waters or into groundwater. Spill prevention control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent a petroleum tank release from impacting navigable waters. The Environmental Protection Agency (“EPA”) has adopted regulations that require us to have permits in order to discharge certain storm water run-off. Storm water discharge permits may also be required by certain states in which we operate. These permits may require us to monitor and sample the storm water run-off. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. We believe that our costs of compliance with these CWA requirements will not have a material adverse effect on our operations.
The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution -- prevention, containment and cleanup, and liability. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the USCG, the United States Department of Transportation Office of Pipeline Safety (“OPS”) or the EPA, as appropriate. Numerous states have enacted laws similar to OPA. Under OPA and similar state laws, responsible parties for a regulated facility from which oil is discharged may be liable for removal costs and natural resource damages. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.
Contamination resulting from spills or releases of petroleum products is an inherent risk within the petroleum pipeline industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems as a result of past operations, we believe any such contamination could be controlled or remedied without having a material adverse effect on our financial position, but such costs are site specific, and we cannot be assured that the effect will not be material in the aggregate.
Our operations are subject to the Federal Clean Air Act (the “Clean Air Act”) and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.
Our permits and related compliance under the Clean Air Act, as well as recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas, may require our operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some of our facilities are included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the Clean Air Act. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than any other similarly situated company.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to climate change. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs, including those that may be used in our operations. It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact our business. However, future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our operations, results of operations and cash flows.
Risk Management Plans
We are subject to the EPA’s Risk Management Plan (“RMP”) regulations at certain locations. This regulation is intended to work with the Occupational Safety and Health Act (“OSHA”) Process Safety Management regulation (see “Safety Matters” below) to minimize the offsite consequences of catastrophic releases. The regulation required us to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program. We are operating in compliance with our risk management program.
We generate hazardous and non-hazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. We also utilize waste minimization and recycling processes to reduce the volumes of our waste. Amendments to RCRA required the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the wastes meet certain treatment standards or the land-disposal method meets certain waste containment criteria.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a facility. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, our pipeline systems generate wastes that may fall within CERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by us requires clean up in the future, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed.
At December 31, 2008, we have an accrued liability of $6.9 million related to sites requiring environmental remediation activities. A discussion of legal proceedings that relate to environmental remediation is included elsewhere in this Report under the caption Item 3. Legal Proceedings.
The operation of tow boats, barges and marine equipment create maritime obligations involving property, personnel and cargo under the General Maritime Law. These obligations can create risks which are varied and include, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third party claims and property damages to vessels and facilities. Routine towage operations can also create risk of personal injury under the Jones Act and General Maritime Law, cargo claims involving the quality of a product and delivery, terminal claims, contractual claims and regulatory issues.
The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. As a result of our marine transportation business acquisition on February 1, 2008, we now engage in maritime transportation between locations in the United States, and as such, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiary that engages in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flag vessels be manned by United States citizens. Foreign-flag seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flag vessel operations compared to foreign-flag vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flag vessel owners. The USCG and ABS maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flag operators than for owners of vessels registered under foreign flags of convenience. Following Hurricane Katrina, and again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated by the United States government. The last suspension ended on October 24, 2005. Future suspensions of the Jones Act or other similar actions could adversely affect our cash flow and ability to make distributions to our unitholders. The Jones Act also provides a remedy in damages for crew members injured in the course and scope of their employment. In certain circumstances, a Jones Act seaman can have dual employers under the borrowed servant doctrine.
Merchant Marine Act of 1936
The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the president of the United States of a national emergency or a threat to the national security, the United States secretary of
transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (including us, provided that we are considered a United States citizen for this purpose). If one of our tow boats or barges were purchased or requisitioned by the United States government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our tow boats is requisitioned or purchased and its associated barge or barges are left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barges. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our tow boats or barges.
DOT Pipeline Compliance Matters
We are subject to regulation by the United States Department of Transportation (“DOT”) under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. The HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the Secretary of Transportation. We believe that we are in material compliance with these HLPSA regulations.
We are subject to the DOT regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks. We believe that we are in material compliance with these DOT regulations.
We are also subject to the DOT Integrity Management regulations, which specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCA”). HCA are defined as populated areas, unusually sensitive environmental areas and commercially navigable waterways. The regulation requires the development and implementation of an Integrity Management Program (“IMP”) that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of HCA pipeline segments. The regulation also requires periodic review of HCA pipeline segments to ensure adequate preventative and mitigative measures exist and that companies take prompt action to address integrity issues raised by the assessment and analysis. In June 2008, DOT extended its pipeline safety regulations, including Integrity Management requirements, to certain rural onshore hazardous liquid gathering lines and certain rural onshore low-stress hazardous liquid pipelines within a buffer area around “unusually sensitive areas.” In compliance with these DOT regulations, we identified our HCA pipeline segments and have developed an IMP. We believe that the established IMP meets the requirements of these DOT regulations.
We are also subject to the requirements of the federal OSHA and comparable state statutes. We believe we are in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.
The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities and local citizens upon request. We are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves certain flammable liquid or gas. We believe we are in material compliance with the OSHA regulations.
We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the ASA or by other service providers. For additional information regarding the ASA, please see “Relationship with EPCO” under Item 13 of this Annual Report. As of December 31, 2008, there were approximately 2,400 EPCO personnel that spend all or a portion of their time engaged in our business. Approximately 1,000 of these individuals devote all of their time performing management and operating duties for us. We reimburse EPCO for 100% of the costs it incurs to employee these individuals. The remaining approximate 1,400 personnel are part of EPCO’s shared service organization and spend all or a portion of their time engaged in our business. The cost for their services is reimbursed to EPCO under the ASA and is generally based on the percentage of time such employees perform services on our behalf during the year. For additional information regarding our relationship with EPCO, please read Item 13 of this Report. In addition to EPCO employees performing services for us, approximately 451 of Cenac’s employees provide services to TEPPCO Marine Services under the transitional operating agreement.
As a large accelerated filer, we electronically file certain documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. From time to time, we may also file registration statements and related documents in connection with equity or debt offerings. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports and other information regarding issuers that file electronically with the SEC, including us.
We provide electronic access to our periodic and current reports on our Internet website (http://www.teppco.com). These reports are available as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC. You may also contact our Investor Relations Department at (800) 659-0059 for paper copies of these reports free of charge.
Item 1A. Risk Factors
There are many factors that may affect us and our joint ventures. Security holders and potential investors in our securities should carefully consider the risk factors set forth below, as well as the discussion of other factors that could affect us or our joint ventures included elsewhere in this Report, including under the captions “Cautionary Note Regarding Forward-Looking Statements,” “Items 1 and 2. Business and Properties,” “Item 3. Legal Proceedings,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and “Item 13. Certain Relationships and Related Transactions, and Director Independence.” If one or more of these risks were to materialize, our business, financial position or results of operations could be materially and adversely affected. We are identifying these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
Risks Relating to Our Business
The current challenges in the financial markets may adversely impact on our business and financial condition.
The current challenges in the financial markets have had, and may continue to have, an impact on our business and our financial condition. We may face significant challenges if these conditions do not improve. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to do so, which could have an adverse impact on our ability to meet our capital commitments and flexibility to react to changing economic and business conditions. The cost of equity capital has become substantially more expensive,
and the distribution yields on new equity that we may issue, if any, may be substantially higher than historical levels.
Our business depends on activity and expenditure levels in the energy industry, which are directly correlated to energy prices. In addition to the bankruptcy of Lehman Brothers (“Lehman”), which is the parent company of one of the lenders under our Revolving Credit Facility, the credit crisis could have a negative impact on our remaining lenders or our customers, causing them to fail to meet their obligations to us. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. New credit facilities and other debt financing from institutional sources have generally become more difficult and expensive to obtain, and there may be a general reduction in the amount of credit available in the markets in which we conduct business. Additionally, many of our customers’ equity values have substantially declined. The combination of a reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ spending. For example, a number of our customers have announced reduced capital expenditure budgets for 2009.
Any of these factors could lead to reduced usage of our pipelines and energy logistics services, which could have a material negative impact on our revenues and prospects.
We may not be able to fully execute our business strategy if we encounter illiquid capital markets or other difficulties in acquisitions and expansions.
Our business strategy contemplates targeting accretive and complementary acquisitions and expansion opportunities that provide attractive long-term, balanced growth in each of our business segments. We regularly consider and enter into discussions regarding strategic transactions that we believe will present opportunities to pursue our strategy.
Acquisitions and expansions may require substantial capital or the incurrence of substantial indebtedness, and any limitations on our access to capital will impair our ability to execute this component of our strategy. If the costs of such capital becomes too expensive, our ability to develop or acquire assets that result in an increase in the cash generated from operations per Unit will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include market conditions and offering or borrowing costs such as interest rates and underwriting discounts. Our prospects and ability to increase distributions may also be limited if we are unable to make accretive acquisitions because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, or if we are outbid by competitors.
Even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per Unit. Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets, personnel and the businesses associated with them and new geographic areas and the diversion of management’s attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we may have no recourse or limited recourse under applicable indemnification provisions. If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Increases in interest rates could increase our borrowing costs, adversely impact our Unit price and our ability to issue additional equity, which could have an adverse effect on our cash flows and our ability to fund our operations.
Due to the recent volatility and decline in the credit markets, the interest rate on our Revolving Credit Facility could increase, which would reduce our cash flows. In addition, interest rates on future credit facilities and
debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, the market price for our Units will be affected by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our Units, and a rising interest rate environment could have an adverse effect on our Unit price and our ability to issue additional equity in order to make acquisitions, to reduce debt or for other purposes.
Our future debt level, downgrades of our debt ratings by credit agencies or a reduction of credit granted by our counterparties may limit our future financial and operating flexibility.
At December 31, 2008, we had outstanding approximately (i) $2.5 billion of consolidated senior debt, consisting of $516.7 million of borrowings under our Revolving Credit Facility and $1.7 billion principal amount of senior notes, and (ii) $300.0 million principal amount of junior subordinated notes.
The amount of our future debt could have significant effects on our operations, because, among other reasons:
Our Revolving Credit Facility contains restrictive financial and other covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur certain additional indebtedness, make distributions in excess of available cash (generally defined in our partnership agreement as consolidated cash receipts less consolidated cash disbursements and cash reserves established by our General Partner), incur certain liens, engage in specified transactions with affiliates and complete mergers, acquisitions and sales of assets. The facility also prevents us from making a distribution if an event of default has occurred or would occur as a result of the distribution. Our breach of these restrictions or restrictions in the provisions of our other indebtedness could permit the holders of the indebtedness to declare all amounts outstanding thereunder to be immediately due and payable and, in the case of our Revolving Credit Facility, to terminate all commitments to extend further credit. Although our Revolving Credit Facility restricts our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial.
In addition to prevailing market conditions, which are susceptible to volatility and decline, our ability to access capital markets on acceptable terms could be affected by our debt level, generally, current maturities and the amount of our debt maturing in the next several years. Moreover, if the rating agencies were to downgrade our credit ratings, our borrowing costs would increase, and we may also experience difficulty accessing capital markets and receiving open lines of trade credit from our counterparties. Such a development could adversely affect our ability to obtain financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness. If we are unable to access the capital markets on acceptable terms at the time a debt obligation becomes due in the future, we may be unable to fund such an obligation, which would constitute a default, or we may be forced to refinance the obligation through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which we may receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected levels.
A downgrade of our credit ratings could result in our being required to post financial collateral up to the amount of our guaranty of indebtedness of our Centennial joint venture, which was $65.0 million at December 31, 2008. Further, from time to time we enter into contracts in connection with our commodity and interest rate hedging activities and crude oil marketing business that require the posting of financial collateral, which may be substantial, if our credit were to be downgraded below investment grade.
Our cash distributions may vary based on our operating performance and level of cash reserves.
Distributions are dependent on the amount of cash we generate and may fluctuate based on our performance. We cannot guarantee that we will continue to pay distributions at the current level each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our General Partner. These factors include but are not limited to the following:
In addition, our ability to pay the minimum quarterly distribution each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make distributions during periods when we record net income.
The interruption of distributions to us from our subsidiaries and joint ventures may affect our ability to satisfy our obligations and to make distributions to our partners.
We are a holding company with no material operations. Our only significant assets are the equity interests we own in our subsidiaries and joint ventures. As a result, we depend upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of their cash to us in order to meet our financial obligations and to allow us to make distributions to our partners. In addition, charter documents and other agreements governing our joint ventures may restrict or limit the occurrence and amount of distributions to us under certain circumstances, including by giving authority to establish available cash for distribution to management committees or other governing bodies that we do not control.
Our profitability depends on demand for and production levels of the products we gather, transport, market and store in the markets we serve.
Declines in crude oil or natural gas production or in the demand for the petroleum products we gather, transport, market and store adversely affect our business. Declines in crude oil or natural gas production may result from a number of factors, including:
We cannot influence or control the production of crude oil we transport or the development of natural gas in the fields we serve. Oil and natural gas prices, which have declined substantially since reaching record levels in mid-2008, play a principal role in the decisions of producers. Even if new oil or natural gas reserves were discovered in areas that we serve, producers may choose not to develop those reserves or may transport or gather them using different systems.
Decreased crude oil production, as well as decreased demand from crude oil refineries or their suppliers, results in lower volumes on our Upstream segment crude oil pipelines and lower associated revenues. In addition, to maintain the volumes of crude oil we purchase in connection with our marketing business, we must continue to contract for new supplies of crude oil to offset volumes lost because of natural declines or volumes lost to competitors. Replacement of lost volumes of crude oil is especially difficult when production levels are generally low, which intensifies competition to gather available production.
Our Midstream Segment gathering systems are connected to natural gas reserves and wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. The amount of natural gas reserves underlying these wells may also be less than we anticipate, and the rate at which production from these reserves declines may be greater than we anticipate. Accordingly, to maintain or increase throughput levels on our gathering systems, we must continually compete for and obtain new natural gas supplies.
With respect to our Downstream and Marine Services Segments, market demand and our revenues from these businesses can be adversely affected by the factors described above with respect to crude oil and natural gas, but demand can also vary based upon the different end uses of the products we transport, market or store. For example:
The Texas Offshore Port System joint venture is expected to represent an important component of our Upstream Segment, requiring an estimated $600.0 million in capital contributions from us through 2011. We and each of the other joint venture partners own a one-third interest in the joint venture, and a subsidiary of Enterprise Products Partners acts as construction manager and will act as operator. Accordingly, we will not have full control over the ongoing operational decisions. If we were unable to make a required capital contribution in Texas Offshore Port System, whether due to our inability to access capital markets or otherwise, our interest could be diluted, and we could suffer other adverse consequences. Further, if we or one of our joint venture partners were unable to make required contributions, the other partners may need to raise and contribute capital above their estimated share in order to complete the project, which capital may not be accessible on economical terms.
A variety of factors outside our control, such as weather, natural disasters, the fluctuating costs of steel and other raw materials and difficulties or inabilities in obtaining rights-of-way, permits or other regulatory approvals, as well as performance by third-party contractors, may result in increased costs or delays in construction. The offshore terminal will require approval by the USCG and issuance of a Deepwater Port License, while the onshore pipeline and storage facilities will be subject to review by the EPA, Army Corps of Engineers and DOT. Some of these
factors are critical to the initiation or completion of significant phases of the project, and may involve time consuming processes. For example, we do not expect to commence significant construction activities on portions of the project until the Deepwater Port License is obtained. The joint venture is also subject to various hazards inherent in the construction and operation of an offshore crude oil port and pipeline system, including damage to the ports, pipelines and related facilities caused by hurricanes and other inclement weather, inadvertent damage from third parties, leaks, operator error, litigation, environmental pollution and risk related to operating in a marine environment. Cost overruns, construction delays or other hazards inherent in the construction and operation of such a facility, whatever the cause, could have a material adverse effect on the success of the our joint venture project or on our business, results of operations, financial condition and prospects.
Our marine transportation business is substantially dependent upon Cenac and subject to liabilities from its operation of our vessels.
We depend on Cenac and its personnel to operate our marine vessels under a transitional operating agreement entered into in connection with the February 2008 acquisition for up to two years from the acquisition. The success of this business is largely dependent on maintaining adequate, licensed crew for our tow boats. If the services of Cenac key personnel become limited or unavailable, or if Cenac fails to operate the vessels at the levels we expect, we may lose customers, experience delays or problems with maintaining the vessels or their cargo or other resultant material adverse effects on our business, financial condition and results of operations. Further, we may not be able to locate or engage qualified replacement personnel on acceptable terms and can give no assurance that we will be able to adequately staff our vessels upon expiration or termination of the transitional operating agreement. While we do not control Cenac, we will have liability to third parties for its actions in operating our vessels, including negligence, during the period in which the transitional operating agreement is in effect.
The U.S. inland waterway infrastructure is aging and may result in increased costs and disruptions to our Marine Services Segment.
Maintenance of the U.S. inland waterway system is vital to our Marine Services Segment’s operations. The system is composed of over 12,000 miles of commercially navigable waterway, supported by over 240 locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river system. The U.S. inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a result, due to the age of the locks, scheduled and unscheduled maintenance outages may be more frequent in nature, resulting in delays and additional operating expenses. Failure of the federal government to adequately fund infrastructure maintenance and improvements in the future would have a negative impact on our ability to provide transportation services for our customers on a timely basis. In addition, any additional user taxes that may be imposed in the future to fund infrastructure improvements would increase our operating expenses.
Our Marine Services Segment could be adversely impacted by a marine accident or spill.
A marine accident or spill event, caused by us or another inland marine transportation company, could close a portion of the inland waterway system for an extended period of time preventing any movements of our marine vessels into or out of the inland waterway river system.
Our Marine Services Segment could be adversely impacted by the construction of inland tank barges by its competitors.
Several of our competitors have announced their intention to increase their tank barge fleets. Additional new construction could create an oversupply of capacity within the industry, which would adversely impact our fleet utilization and results of operation.
Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.>
The construction of new energy logistics assets involves numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things, the following:
A materialization of any of these risks could adversely affect our ability to achieve expected cash flows or realize benefits from expansion opportunities or construction projects.
Our tariff rates are subject to review and possible adjustment by federal and state regulators, which could have a material adverse effect on our financial condition and results of operations.
The FERC, pursuant to the ICA, as amended, the Energy Policy Act and rules and orders promulgated thereunder, regulates the tariff rates for our interstate common carrier pipeline operations. To be lawful under the ICA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with FERC. In addition, pipelines may not confer any undue preference upon any shipper. Shippers may protest, and the FERC may investigate, the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful. The FERC and interested parties can also challenge tariff rates that have become final and effective. The FERC also can order reparations for overcharges effective two years prior to the date of a complaint. Because of the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues.
The FERC uses prescribed rate methodologies for approving regulated tariff rates for transporting crude oil and refined products. Our interstate tariff rates are either market-based or derived in accordance with the FERC’s indexing methodology, which currently allows a pipeline to increase its rates by a percentage linked to the producer price index for finished goods. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs. Changes in the FERC’s approved methodology for approving rates, or challenges to our application of that methodology, could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow.
The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.
Although our natural gas gathering systems are generally exempt from FERC regulation under the Natural Gas Act of 1938, FERC regulation still significantly affects our natural gas gathering business. In recent years, the FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue this approach, it could have an adverse effect on the rates we are able to charge in the future. In addition, our natural gas gathering operations could be adversely affected in the future should they become subject to the application of federal regulation of rates and services or if the states in which we operate adopt policies imposing
more onerous regulation on gathering. Additional rules and legislation pertaining to these matters are considered and adopted from time to time at both state and federal levels. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.
Our partnership status may be a disadvantage to us in calculating our cost of service for rate-making purposes.
Currently, none of our tariffs are calculated using cost of service rate methodologies. If, however, in the future our tariffs are calculated using a cost of service rate methodology, our revenues might be adversely affected by changes in the FERC’s ratemaking policies. For example, there are several ongoing proceedings involving other pipelines in which the FERC is refining its policies regarding income tax allowances and rate of return.
In May 2005, FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. In December 2005, FERC issued its first significant case-specific review of the income tax allowance issue in another pipeline partnership’s rate case. FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16, 2005 order were appealed to the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”). The D.C. Circuit denied these appeals in May 2007 and fully upheld FERC’s new tax allowance policy and the application of that policy in the December 2005 order.
In December 2006, FERC issued a new order addressing rates on another pipeline. In the new order, FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. This and other proceedings pertaining to the FERC’s income tax allowance policy remain pending.
In April 2008, the FERC issued a Policy Statement in which it declared that it would permit MLPs to be included in rate of return proxy groups for determining rates for services by natural gas and oil pipelines. It also addressed the application to limited partnership pipelines of the FERC’s discounted cash flow methodology for determining rates of return on equity. The FERC applied the new policy to several ongoing proceedings involving other pipelines. The FERC’s rate of return policy remains subject to change.
The ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service as well as rates of return, particularly with respect to pipelines organized as partnerships. If any of our rates were to be calculated using cost of service rate methodologies in the future, the outcome of these ongoing proceedings could adversely affect our revenues.
Competition could adversely affect our operating results.
We face substantial competition in our transportation, gathering and marketing activities. Some of our competitors have capital resources many times greater than ours or access to or control of greater supplies of hydrocarbons and related products.
Our refined products, LPG, NGL and marine transportation businesses compete with other pipelines and marine transportation companies in the areas they serve, as well as with trucks and railroads in some of those areas. Substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business.
Our crude oil transportation, gathering and marketing business competes with common carriers and proprietary pipelines owned and operated by major integrated oil companies, large independent pipeline companies and other companies in the areas where our pipelines deliver products, independent gatherers and marketers and financial institutions with trading platforms. The crude oil gathering and marketing business can be characterized by thin margins and strong competition for supplies of crude oil at the wellhead, and declines in domestic crude oil production have intensified competition in this line of our business.
Third party shippers generally do not have long-term contractual commitments to ship crude oil or refined products on our pipelines. Accordingly, shippers have the ability to elect to transport volumes on competitors’ pipelines or by alternative means, which would reduce the volumes on our pipelines and associated revenues.
Our natural gas gathering business competes with major integrated oil companies and independent gas gatherers in seeking new supplies of natural gas for its systems. Alternate gathering facilities are available to the producers we serve, and producers may also elect to construct proprietary gathering systems.
Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.
Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to fully eliminate customer credit risk. Further, adverse economic conditions, such as the credit crisis that developed in the fourth quarter of 2008, increase the risk of nonpayment and nonperformance by customers, particularly for customers that are smaller companies. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk.
Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. For the years ended December 31, 2008, 2007 and 2006, Valero accounted for 21%, 16% and 14%, respectively, of our total consolidated revenues, and for the years ended December 31, 2008, 2007 and 2006, BP Oil Supply Company accounted for 16%, 14% and 11%, respectively, of our total consolidated revenues. Additionally, for the year ended December 31, 2007, Shell Trading Company accounted for 12% of our total consolidated revenues. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2008, 2007 and 2006.
Our risk management policies cannot eliminate all commodity price risks. In addition, any non-compliance with our risk management policies could result in significant financial losses.
To enhance utilization of certain assets and our operating income, we purchase petroleum products. Generally, it is our policy to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to establish a margin for the commodity purchased by selling the same commodity for physical delivery to third party users, such as producers, wholesalers, independent refiners, marketing companies or major oil companies. These policies and practices cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when a commodity is purchased against one pricing index and sold against a different index. Moreover, we are exposed to some risks that are not hedged, including price risks on product inventory, such as pipeline linefill, which must be maintained in order to facilitate transportation of the commodity on our pipelines. In addition, our marketing operations involve the risk of non-compliance with our risk management policies. We cannot assure you that our processes and procedures will detect and prevent all violations of our risk management policies, particularly if deception or other intentional misconduct is involved.
Our pipelines are dependent on their interconnections with other pipelines to reach their destination markets.>
Decreased throughput on interconnected pipelines due to testing, line repair and reduced pressures could result in reduced throughput on our pipeline systems. Such reduced throughput may adversely impact our profitability.
The success of our Jonah gas gathering operations is substantially dependent upon Enterprise Products Partners.
We own our interest in the Jonah system, which represents a significant component of our Midstream Segment and its prospects, through a joint venture with Enterprise Products Partners, which is under the common control of Enterprise GP Holdings with us and which is a significant customer of our Midstream Segment (see “– Midstream Segment – Gathering of Natural Gas, Transportation of NGLs and Fractionation of NGLs”). The joint venture is governed by a management committee comprised of two representatives approved by an Enterprise Products Partners’ affiliate and two representatives approved by subsidiaries of ours, all four of which are EPCO employees. We own an approximate 80.64% interest in the joint venture, with Enterprise Products Partners’ affiliate owning the remaining approximate 19.36%. Each representative on the management committee is entitled to one vote, and the joint venture agreement generally requires the affirmative vote of a majority of the members of the management committee to approve an action. We and Enterprise Products Partners may not always agree on the best course of action for the joint venture. If such a disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in our best interests. Further, Enterprise Products Partners may experience unanticipated delays or costs in operation of the joint venture, which could require additional capital contributions by us and Enterprise Products Partners or diminish expected benefits from the joint venture. Any of these factors could materially and adversely affect our results of operations, financial condition and prospects.
In accordance with midstream industry practice, we do not obtain third party evaluations of natural gas reserves dedicated to our gathering systems, including Jonah. Accordingly, volumes of natural gas gathering on our pipeline systems in the future could be less than we anticipate, which could adversely affect our cash flow and our ability to make cash distributions to unitholders.
In accordance with midstream industry practice, we do not obtain third party evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to those systems or the anticipated lives of such reserves. If the total reserves or estimated lives of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our systems in the future could be less than we expect. A decline in the volumes of natural gas gathered on our pipeline systems could have an adverse effect on our business, results of operations and financial condition.
The use of derivative financial instruments could result in material financial losses by us.
We historically have sought to limit a portion of the adverse effects resulting from changes in commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms from time to time. To the extent that we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though monitored by management, hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is imperfect, or hedging policies and procedures are not followed. Adverse economic conditions, such as the financial crisis that developed in the fourth quarter of 2008, increase the risks of nonpayment or nonperformance by our hedging counterparties. See Note 6 in the Notes to Consolidated Financial Statements for a discussion of our financial instruments.
Our pipeline integrity program and periodic tank maintenance requirements may impose significant costs and liabilities on us.
The DOT issued final rules (effective March 2001 with respect to hazardous liquid pipelines and February 2004 with respect to natural gas pipelines) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and take measures to protect pipeline segments located in what the rules refer to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The ultimate costs of compliance with this rule are difficult to predict. The majority of the costs to comply with the integrity management rule are associated with pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in “high consequence areas” can have a significant impact on the costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines as required by the DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
In June 2008, DOT issued a Final Rule extending its pipeline safety regulations, including integrity management requirements, to certain rural onshore hazardous liquid gathering lines and certain rural onshore low-stress hazardous liquid pipelines within a buffer area around “unusually sensitive areas.” The issuance of these new gathering and low-stress pipeline safety regulations, including requirements for integrity management of those pipelines, is likely to increase the operating costs of our pipelines subject to such new requirements.
The American Petroleum Institute Standard 653 (“API 653”) is an industry standard for the inspection, repair, alteration and reconstruction of existing storage tanks. API 653 requires regularly scheduled inspection and repair of tanks remaining in service. Periodic tank maintenance requirements could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our storage tanks.
Our operations are subject to governmental laws and regulations relating to the protection of the environment and safety which may expose us to significant costs and liabilities. Additionally, as a result of our Marine Services Segment, we are subject to additional laws and regulations, including environmental regulations, that may adversely affect the cost, manner or feasibility of doing business in that segment.
Our facilities and operations are subject to multiple environmental, health and safety obligations and potential liabilities under a variety of federal, state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations. If an accidental leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination. Any or all of this could materially affect our results of operations and cash flows. We currently own or lease, and have owned or leased, many properties that have been used for many years to terminal or store crude oil, petroleum products or other chemicals. Owners, tenants or users of these properties may have disposed of or released hydrocarbons or solid wastes on or under them. Additionally, some sites we operate are located near current or former refining and terminaling operations. There is a risk that contamination has migrated from those sites to ours.
Further, we cannot ensure that existing environmental regulations will not be revised or that new regulations, such as regulations designed to reduce the emission of greenhouse gases, will not be adopted or become applicable to us. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that
result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
Various state and federal governmental authorities, including the EPA, the Bureau of Land Management, the DOT and OSHA, have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Liability may be incurred without regard to fault under CERCLA, RCRA, and analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipeline systems pass, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.
Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely affect our products and activities, including storage, transportation and construction and maintenance activities, as well as waste management and air emissions. Federal and state agencies also could impose additional safety requirements, any of which could affect our profitability.
Contamination resulting from spills or releases of petroleum products is an inherent risk within the petroleum pipeline industry. While the costs of remediating groundwater contamination are generally site-specific, such costs can vary substantially and may be material.
Increasingly stringent federal, state and local laws and regulations governing worker health and safety and the manning, construction and operation of marine vessels may significantly affect our marine transportation operations. Many aspects of the marine industry are subject to extensive governmental regulation by the USCG, the DOT, the Department of Homeland Security, the National Transportation Safety Board and the U.S. Customs and Border Protection (“CBP”), and to regulation by private industry organizations such as the ABS. The USCG and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards. The USCG is authorized to inspect vessels at will.
Our marine transportation operations are also subject to state and local laws and regulations that control the discharge of pollutants into the environment or otherwise relate to environmental protection. Compliance with such laws, regulations and standards may require installation of costly equipment or operational changes. Failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our marine operations. Some environmental laws often impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Under the OPA, owners, operators and bareboat charterers are jointly and severally strictly liable for the discharge of oil within the internal and territorial waters of, and the 200-mile exclusive economic zone around, the United States. Additionally, an oil spill from one of our vessels could result in significant liability, including fines, penalties, criminal liability and costs for natural resource damages. The potential for these releases could increase if we increase our fleet capacity. In addition, most states bordering on a navigable waterway have enacted legislation providing for potentially unlimited liability for the discharge of pollutants within their waters.
Our marine services business would be adversely affected if we failed to comply with the Jones Act provisions on coastwise trade, or if those provisions were modified, repealed or waived.
We are subject to the Jones Act and other federal laws that restrict maritime transportation between points in the United States to vessels built and registered in the United States and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of our common units and other partnership interests. If we do not comply with these restrictions, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels.
In the past, interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag competition for trades and cargoes currently reserved for U.S.-flag vessels under the Jones Act and cargo preference laws. We believe that interest groups may continue efforts to modify or repeal the Jones Act and cargo preference laws currently benefiting U.S.-flag vessels. If these efforts are successful, it could result in increased competition, which could reduce our revenues and cash available for distribution.
The Secretary of the Department of Homeland Security is vested with the authority and discretion to waive the coastwise laws to such extent and upon such terms as he may prescribe whenever he deems that such action is necessary in the interest of national defense. For example, in response to the effects of Hurricanes Katrina and Rita, the Secretary of the Department of Homeland Security waived the coastwise laws generally for the transportation of petroleum products from September 1 to September 19, 2005 and from September 26, 2005 to October 24, 2005. In the past, the Secretary of the Department of Homeland Security has waived the coastwise laws generally for the transportation of petroleum released from the Strategic Petroleum Reserve undertaken in response to circumstances arising from major natural disasters. Any waiver of the coastwise laws, whether in response to natural disasters or otherwise, could result in increased competition from foreign marine vessel operators, which could reduce our revenues and cash available for distribution.
Our marine services business would be adversely affected if the U.S. government purchases or requisitions any of our vessels under the Merchant Marine Act.
The Merchant Marine Act of 1936 is a federal law that provides that the U.S. Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If any of our vessel are purchased or requisitioned for an extended period of time by the U.S. government, such transactions could have a material adverse affect on our results of operations, cash flow, and could reduce cash available for distribution.
Maritime claimants could arrest the vessels carrying our cargoes.
Crew members, suppliers of goods and services to a vessel, other shippers of cargo and other parties may be entitled to a maritime lien against that vessel for unsatisfied debts, claims or damages. In many jurisdictions, a maritime lienholder may enforce its lien by arresting a vessel through foreclosure proceedings. The arrest or attachment of one of our vessels could substantially delay our shipment. In addition, in some jurisdictions, under the “sister ship” theory of liability, a claimant may arrest both the vessel that is subject to the claimant’s maritime lien and any “associated” vessel, which is any vessel owned or controlled by the same owner. Claimants could try to assert “sister ship” liability against one of our vessels for claims relating to a vessel with which we have no relation.
Terrorist attacks aimed at our facilities could adversely affect our business.
On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11th attacks, the United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.>
Our operations are subject to the many hazards inherent in the onshore and marine transportation and terminaling of refined products, LPGs, NGLs, petrochemicals and crude oil and in the gathering, compressing, and treating of natural gas, including ruptures, leaks, fires, spills, severe weather and other disasters. These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. EPCO maintains insurance coverage on land-based and marine operations on our behalf, although insurance will not cover many types of hazards that might occur, including certain environmental accidents, and if covered we may still have responsibility for any applicable deductibles. As a result of market conditions, premiums
and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. For example, changes in the insurance markets resulting from the hurricanes of 2005 and 2008 have made it more difficult for us to obtain certain types of coverage. The recent global financial crisis may negatively impact insurance carriers and affect our ability to obtain coverage. As a result, EPCO may not be able to renew existing insurance policies on our behalf or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
We depend on the services and personnel of EPCO, which is controlled by Dan L. Duncan.
Other than certain operational personnel for our Marine Services Segment, all of our management, administrative and operating functions are performed by employees of EPCO pursuant to the ASA. Dan L. Duncan directly owns and controls EPCO and through Dan Duncan LLC, owns and controls EPE Holdings, the general partner of Enterprise GP Holdings. Enterprise GP Holdings owns all of the membership interests of our General Partner. The principal business activity of our General Partner is to act as our managing partner. The executive officers of our General Partner and other senior operational personnel who run our business are employees of EPCO. These officers and personnel have many years of relevant business experience, and future unplanned departures could have a material adverse effect on our business, financial condition and results of operations. None of our officers are parties to employment agreements with EPCO or our General Partner.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for specified periods of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, or increased costs to renew such rights, could have a material adverse effect on our business, financial position, results of operations or cash flows.
Mergers among our customers or competitors could result in lower volumes being shipped by us, thereby reducing the amount of cash we generate.
The credit crisis and related instability in the global financial system may drive our customers and competitors to pursue mergers or other business combinations. Such transactions among our existing customers or competitors could provide strong economic incentives for the combined entities to utilize systems other than ours, and we could experience difficulty in replacing lost volumes and revenues. Because a significant portion of our operating costs are fixed, a reduction in volumes would result not only in a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to unitholders.
Risks Relating to Our Units as a Result of Our Partnership Structure
We may issue additional limited partnership interests, diluting existing interests of unitholders and benefiting our General Partner.
Our Partnership Agreement allows us to issue additional Units and other equity securities without unitholder approval. These additional securities may be issued to raise cash or acquire additional assets or businesses or for other partnership purposes. Our Partnership Agreement does not limit the number of Units and other equity securities we may issue. If we issue additional Units or other equity securities, the proportionate partnership interest and voting power of our existing unitholders will decrease and the ratio of taxable income to distributions may increase. Such issuances could negatively affect the amount of cash distributed to unitholders and the market price of our Units.
Cost reimbursements and fees due EPCO and its affiliates may be substantial and will reduce our cash available for distribution to holders of our Units.>
Prior to making any distribution on our Units, we will reimburse EPCO and its affiliates, including our General Partner, for expenses they incur on our behalf for operations and management functions. The payment of these amounts and allocated overhead to EPCO and its affiliates could adversely affect our ability to pay cash distributions to holders of our Units. These amounts include all costs in managing and operating our business, including compensation of executives for time allocated to us, director compensation, costs for rendering administrative staff and support services and overhead allocated to us by EPCO. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence” in this Report. In addition, our General Partner and its affiliates may provide other services to us for which we will be charged fees as determined by our General Partner.
Our General Partner and its affiliates may have conflicts with our partnership.
The directors and officers of our General Partner and its affiliates (including Enterprise GP Holdings, EPCO and other affiliates of EPCO) have duties to manage the General Partner in a manner that is beneficial to its owner, Enterprise GP Holdings, which is controlled by Dan L. Duncan. At the same time, the General Partner has duties to manage us in a manner that is beneficial to us. Enterprise GP Holdings also controls other publicly traded partnerships, Enterprise Products Partners and Duncan Energy Partners, that engage in similar lines of business. We have significant business relationships with Enterprise Products Partners, EPCO and other entities controlled by Mr. Duncan, including our Jonah and Texas Offshore Port System joint ventures. Mr. Duncan’s economic interests in Enterprise Products Partners and these other related entities are more substantial than his economic interest in us. Therefore, our General Partner’s duties to us may conflict with the duties of its officers and directors to its owner. As a result of these conflicts of interest, our General Partner may favor its own interest or those of Enterprise GP Holdings or its owners or affiliates over the interest of our unitholders. Possible conflicts may include, among others, the following:
Please read “Item 13. Certain Relationships and Related Party Transactions, and Director Independence” in this Report.
Unitholders have limited voting rights and control of management.
Our General Partner manages and controls our activities. Unitholders have no right to elect the General Partner or the directors of the General Partner on an annual or other ongoing basis. However, if the General Partner resigns or is removed, its successor may be elected by holders of a majority of the Units. Unitholders may remove the General Partner only by a vote of the holders of at least 66 2/3% of the Units. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations. As a result, unitholders will have limited influence on matters affecting our operations, and third parties may find it difficult to gain control of us or influence our actions.
EPCO’s employees may be subjected to conflicts in managing our business and the allocation of time and compensation costs between our business and the business of EPCO and its other affiliates.
We have no officers or employees and rely on officers of our General Partner and employees of EPCO and its affiliates to conduct our business. These relationships may create conflicts of interest regarding corporate opportunities and other matters, and the resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping employees allocate their time among us, EPCO and other affiliates of EPCO and may face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.
The ASA governs business opportunities among entities controlled by our General Partner, including us (“TEPPCO Companies”), entities controlled by the general partners of Enterprise GP Holdings and Enterprise Products Partners, including Enterprise GP Holdings and Enterprise Products Partners (“Enterprise Companies”), Duncan Energy Partners and its general partner and EPCO and its other affiliates. Under the ASA, we have no obligation to present any business opportunity offered to or discovered by us to the Enterprise Companies, and they are not obligated to present business opportunities that are offered to or discovered by them to us. However, the agreement requires that business opportunities offered to or discovered by EPCO, which is affiliated with both the TEPPCO Companies and the Enterprise Companies, be offered first to certain Enterprise Companies before they may be pursued by EPCO and its other affiliates or offered to us.
We do not have a compensation committee, and substantial components of the compensation of our executive officers and other key employees, including base salary, are not reviewed or approved by our non-executive directors. The determination of executive officer and key employee compensation could involve conflicts of interest resulting in economically unfavorable arrangements for us.
Our Partnership Agreement limits our General Partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement:
Our General Partner has a limited call right that may require unitholders to sell their Units at an undesirable time or price.
If at any time persons other than our General Partner and its affiliates own less than 15% of the Units then outstanding, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining Units held by unaffiliated persons at a price not less than the then-current market price. As a result, unitholders may be required to sell their Units at an undesirable time or price and may therefore not receive any return on their investment. They may also incur a tax liability upon a sale of their Units.
Our unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
Under Delaware law, our General Partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our General Partner. Further, unitholders could be held liable for our obligations to the same extent as a General Partner if a court determined that:
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a limited partner may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
The credit and risk profile of our General Partner and its owners could adversely affect our credit ratings and profile, which could increase our borrowing costs or hinder our ability to raise capital.>
The credit and business risk profiles of the general partner or owners of the general partner may be factors in credit evaluations of an MLP. This is because the general partner can exercise significant influence over the business activities of the partnership, including its cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of the general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.
Entities controlling the owner of our General Partner have significant indebtedness outstanding and are dependent principally on the cash distributions from the general partner and limited partner equity interests in us, Enterprise GP Holdings, Enterprise Products Partners and Energy Transfer Equity, L.P. to service such indebtedness. Any distributions by us to such entities will be made only after satisfying our then current obligations to our creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect our separateness from our General Partner and the entities that control our General Partner, our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of Dan L. Duncan or the entities that control our General Partner were viewed as substantially lower or more risky than ours. In addition, the 100% membership interest in our General Partner and the 4,400,000 of our Units that are owned by Enterprise GP Holdings are pledged under Enterprise GP Holdings’ credit facility. Upon an event of default under that credit facility, the lenders could foreclose on Enterprise GP Holdings’ assets, which could ultimately result in a change in control of our General Partner and a change in the ownership of our Units held by Enterprise GP Holdings.
Control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of Enterprise GP Holdings from transferring all or a portion of its ownership interest in our General Partner to a third party. Such a third party would then be in a position to replace the board of directors and officers of our General Partner with its own choices and thereby influence the decisions taken by the board of directors and officers.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. The amount of cash available for distribution to you would be substantially reduced if the Internal Revenue Service (“IRS”) treats us as a corporation or we become subject to a material amount of entity-level taxation for state or foreign tax purposes.>
The anticipated after-tax economic benefit of an investment in the Units depends largely on our being treated as a partnership for federal income tax purposes. Because we are a publicly traded partnership, this requires that 90% or more of our gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code (the “Qualifying Income Requirement”). We have not requested, and do not plan to request, a ruling from the IRS regarding our treatment as a partnership for federal income tax purposes.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our Units.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Our Partnership Agreement currently provides that if we become
subject to taxation as a corporation or otherwise subject to entity-level taxation as a result of the enactment of new legislation or a change in the interpretation of existing law by a government taxing authority, the minimum quarterly distribution amount and the target distribution level will be adjusted to reflect the impact of the additional taxes upon us.
In addition, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are subject to an entity-level tax on the portion of our income generated in Texas. Specifically, the Revised Texas Franchise Tax is imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such tax on us by Texas, or any other state, will reduce the cash available for distribution to you.
Our tax treatment as a partnership for federal income tax purposes is subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
Our treatment as a partnership for federal income tax purposes may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the Qualifying Income Requirement, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our Units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code Section 7704(d) and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Units.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our Units, and the cost of an IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution.
You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from that income.
Tax gain or loss on the disposition of Units could be more or less than expected.
If you sell your Units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those Units. Prior distributions to you in excess of the total net taxable income you were allocated for a Unit, which decreased your tax basis in that Unit, will, in effect, become taxable income to you if you sell the Unit at a price greater than your tax basis in that Unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. If you sell your Units, you may incur a tax liability in excess of the amount of cash you receive from the sale. If the IRS successfully contests some positions we take, unitholders could recognize more gain on the sale of Units than would be the case under those positions, without the benefit of decreased income in prior years.
Tax-exempt entities and foreign persons face unique tax issues from owning Units that may result in adverse tax consequences to them.>
Investment in Units by tax-exempt entities, such as individual retirement accounts (“IRAs”), other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person you should consult your tax advisor before investing in our Units.
We treat each purchaser of our Units as having the same tax benefits without regard to the actual Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Units.
Because we cannot match transferors and transferees of Units, we must maintain uniformity of the economic and tax characteristics of our Units to a purchaser of Units. We take depreciation and amortization positions that are intended to maintain such uniformity. These depreciation and amortization positions may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of Units and could have a negative impact on the value of our Units or result in audit adjustments to your tax returns.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. If this occurs, you will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to you with respect to that period.
We prorate our items of income, gain, loss, and deduction between transferors and transferees of our Units each month based upon the ownership of our Units on the first day of each month, instead of on the basis of the date a particular Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss, and deduction between transferors and transferees of our Units each month based upon the ownership of our Units on the first day of each month, instead of on the basis of the date a particular Unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
A unitholder whose Units are loaned to a “short seller” to cover a short sale of Units may be considered as having disposed of those Units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those Units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose Units are loaned to a “short seller” to cover a short sale of Units may be considered as having disposed of the loaned Units, the unitholder may no longer be treated for tax purposes as a partner with respect to those Units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those Units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their Units.
We have adopted certain methodologies that may result in a shift of income, gain, loss and deduction between the General Partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our Units.
When we issue additional Units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the General Partner, which may be unfavorable to such unitholders. Moreover, under this methodology, subsequent purchasers of Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the General Partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of Units and could have a negative impact on the value of the Units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
Unitholders may be subject to foreign, state and local taxes and return filing requirements in states and jurisdictions where they do not live as a result of investing in our Units.
In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. Our operating subsidiaries own assets and do business in Alabama, Arkansas, Colorado, Georgia, Illinois, Indiana, Kansas, Kentucky, Louisiana, Mississippi, Missouri, Montana, Nebraska, New Mexico, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Dakota, Tennessee, Texas, Utah, West Virginia and Wyoming. Each of these states, other than South Dakota, Texas and Wyoming currently imposes a personal income tax and many impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, state and local, as well as foreign tax returns.
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
In 1991, we were named as a defendant in a matter styled Jimmy R. Green, et al. v. Cities Service Refinery, et al. as filed in the 26th Judicial District Court of Bossier Parish, Louisiana. The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants. The former refinery is located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property. The plaintiffs have pursued certification as a class and have significantly increased their demand to approximately $175.0 million. We have never owned any interest in the refinery property made the basis of this action, and we do not believe that we contributed to any alleged contamination of this property. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of our other unitholders, and derivatively on our behalf, concerning proposals made to our
unitholders in our definitive proxy statement filed with the SEC on September 11, 2006 (“Proxy Statement”) and other transactions involving us and Enterprise Products Partners or its affiliates. Mr. Brinckerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants the General Partner; the Board of Directors of the General Partner; EPCO; Enterprise Products Partners and certain of its affiliates and Dan L. Duncan. We are named as a nominal defendant.
The amended complaint alleges, among other things, that certain of the transactions adopted at a special meeting of our unitholders on December 8, 2006, including a reduction of the General Partner’s maximum percentage interest in our distributions in exchange for Units (the “Issuance Proposal”), were unfair to our unitholders and constituted a breach by the defendants of fiduciary duties owed to our unitholders and that the Proxy Statement failed to provide our unitholders with all material facts necessary for them to make an informed decision whether to vote in favor of or against the proposals. The amended complaint further alleges that, since Mr. Duncan acquired control of the General Partner in 2005, the defendants, in breach of their fiduciary duties to us and our unitholders, have caused us to enter into certain transactions with Enterprise Products Partners or its affiliates that were unfair to us or otherwise unfairly favored Enterprise Products Partners or its affiliates over us. The amended complaint alleges that such transactions include the Jonah joint venture entered into by us and an Enterprise Products Partners’ affiliate in August 2006 (citing the fact that our ACG Committee did not obtain a fairness opinion from an independent investment banking firm in approving the transaction), and the sale by us to an Enterprise Products Partners affiliate of the Pioneer plant in March 2006. As more fully described in the Proxy Statement, the ACG Committee recommended the Issuance Proposal for approval by the Board of Directors of the General Partner. The amended complaint also alleges that Richard S. Snell, Michael B. Bracy and Murray H. Hutchison, constituting the three members of the ACG Committee at that time, cannot be considered independent because of their alleged ownership of securities in Enterprise Products Partners and its affiliates and/or their relationships with Mr. Duncan.
The amended complaint seeks relief (i) awarding damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; (ii) rescinding all actions taken pursuant to the Proxy vote and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. Pre-trail discovery in this proceeding is underway. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
In 1999, our Arcadia, Louisiana, facility and adjacent terminals were directed by the Remediation Services Division of the Louisiana Department of Environmental Quality (“LDEQ”) to pursue remediation of environmental contamination. Effective March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. At December 31, 2008, we have an accrued liability of $0.5 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.
We received a notice of probable violation from the DOT on April 25, 2005, for alleged violations of pipeline safety regulations at our Todhunter facility, with a proposed $0.4 million civil penalty. We responded on June 30, 2005, by admitting certain of the alleged violations, contesting others and requesting a reduction in the proposed civil penalty. We do not expect any settlement, fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.
In October 2005, Williams Gas Processing, n/k/a Williams Field Services Company, LLC (“Williams”) notified Jonah that the gas delivered to Williams’ Opal Gas Processing Plant (“Opal Plant”) allegedly failed to conform to quality specifications of the Interconnect and Operator Balancing Agreement (“Interconnect Agreement”) which has allegedly caused damages to the Opal Plant in excess of $28.0 million. On July 24, 2007, Jonah filed suit against Williams in Harris County, Texas seeking a declaratory order that Jonah was not liable to Williams. In addition, on August 24, 2007, Williams filed a complaint in the 3rd Judicial District Court of Lincoln County, Wyoming alleging that Jonah was delivering non-conforming gas from its gathering customers in the Jonah system to the Opal Plant, in violation of the Interconnect Agreement. Jonah denies any liability to Williams. Discovery is ongoing.
In addition to the proceedings discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
Item 5. Market for Registrant’s Units, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our Units are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “TPP”. The high and low trading prices of our Units in 2008 and 2007, respectively, as reported on the NYSE, were as follows:
Based on the information received from our transfer agent, as of February 2, 2009, there were approximately 1,258 unitholders of record of our Units.
The quarterly cash distributions on our Units for the years ended December 31, 2008 and 2007, were as follows:
We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its reasonable discretion. Pursuant to the Partnership Agreement, the General Partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds (see Note 13 in the Notes to Consolidated Financial Statements).
We are a publicly traded MLP and are not subject to federal income tax. Instead, unitholders are required to report their allocated share of our income, gain, loss, deduction and credit, regardless of whether we make distributions. We have made quarterly distribution payments since May 1990.
Distributions of cash paid by us to a unitholder will not result in taxable gain or income except to the extent the aggregate amount distributed exceeds the tax basis of the Units owned by the unitholder.
Recent Sales of Unregistered Securities
There were no sales of unregistered securities in 2008 other than as previously reported in the 2007 Form 10-K and our Current Report on Form 8-K filed on September 9, 2008.
Units Authorized for Issuance Under Equity Compensation Plan
Please read the information included under Item 12 of this Report, which is incorporated by reference into this Item 5.
Issuer Purchases of Equity Securities
In November 2008, 1,000 of our restricted unit awards vested and were converted into Units, of which 384 of these Units were sold back to us by the employee to cover related withholding tax requirements. The average price paid per Unit was $24.33. For additional information regarding outstanding equity awards, please refer to Note 4 in the Notes to Consolidated Financial Statements and Item 11. Executive Compensation.
Item 6. Selected Financial Data
The following tables set forth, for the periods and at the dates indicated, our selected consolidated financial data, which is derived from our audited consolidated financial statements, and our selected operating data. The selected financial data as of and for the years ended December 31, 2006, 2005 and 2004 reflect Jonah’s Pioneer plant, which was sold on March 31, 2006, as discontinued operations. The financial data should be read in conjunction with our audited consolidated financial statements included in the Index to Consolidated Financial Statements on page F-1 of this Report. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.