Item 3. Legal Proceedings
Toxic Tort Litigation - Seymour, Indiana
In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et. al. v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. We have filed an answer to both complaints, denying the allegations, as well as various other motions. These cases are not covered by insurance. Discovery is ongoing, and we are defending ourselves vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages that they are seeking in the suit. We cannot estimate the loss, if any, associated with these pending lawsuits.
Other Litigation
On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et. al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiff’s property, leaked toxic products onto the plaintiff’s property. The plaintiffs further contend that this leak caused damages to the plaintiffs. We have filed an answer to the plaintiff’s petition denying the allegations. The plaintiffs have not stipulated the amount of damages they are seeking in the suit. We are defending ourselves vigorously against the lawsuit. We
cannot estimate the damages, if any, associated with this pending lawsuit; however, this case is covered by insurance.
On April 19, 2002, we, through our subsidiary TEPPCO Crude Oil, L.P., filed a declaratory judgment action in the U.S. District Court for the Western District of Oklahoma against D.R.D. Environmental Services, Inc. (“D.R.D.”) seeking resolution of billing and other contractual disputes regarding potential overcharges for environmental remediation services provided by D.R.D. On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in the amount of $2,243,525, and for unspecified damages for alleged tortious interference with D.R.D.’s contractual relations with DEFS. We have denied the counterclaims. Discovery is ongoing. If D.R.D. should be successful, management believes that a substantial portion of the $2,243,525 breach of contract claim will be covered under an indemnity from DEFS. We cannot predict the outcome of the litigation against us; however, we are defending ourselves vigorously against the counterclaim. 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 addition to the litigation 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 lawsuits and 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.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.
Item 5. Market for Registrant’s Units and Related Unitholder Matters
Our Limited Partner Units are listed and traded on the New York Stock Exchange under the symbol TPP. The high and low trading prices of our Limited Partner Units in 2002 and 2001, respectively, as reported on The New York Times, were as follows:
Based on the information received from our transfer agent and from brokers and nominees, we estimate the number of beneficial unitholders of our Limited Partner Units as of March 14, 2003, to be approximately 51,300.
The quarterly cash distributions for 2001 and 2002 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 sole discretion. Pursuant to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds (see Note 13. Quarterly Distributions of Available Cash).
We are a publicly traded master limited partnership 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 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.
Item 6.
Item 6. Selected Financial Data
The following tables set forth, for the periods and at the dates indicated, our selected consolidated financial and operating data. The financial data was derived from our consolidated financial statements and should be read in conjunction with our audited consolidated financial statements included in the Index to Financial Statements on page of this Report. See also Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
The following information is provided to facilitate increased understanding of our 2002, 2001 and 2000 consolidated financial statements and our accompanying notes listed in the Index to Financial Statements on page of this Report. Accounting policies that are among the most critical to the portrayal of our financial condition and results of operations are discussed under “Critical Accounting Policies.” Material period-to-period variances in the consolidated statements of income are discussed under “Results of Operations.” The “Financial Condition and Liquidity” section analyzes cash flows and financial position. Discussion included in “Other Considerations” addresses trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings.
We operate and report in three business segments:
•
Downstream Segment - transportation and storage of refined products, LPGs and petrochemicals;
•
Upstream Segment - gathering, transportation, marketing and storage of crude oil; and distribution of lubrication oils and specialty chemicals; and
•
Midstream Segment - gathering of natural gas, fractionation of NGLs and transportation of NGLs.
Our reportable segments offer different products and services and are managed separately because each requires different business strategies. TEPPCO GP, our wholly owned subsidiary, acts as managing general partner of our Operating Partnerships with a 0.001% general partner interest and manages our subsidiaries.
Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which was previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation.
Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation
of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand in the Northeast for propane, a major fuel for residential heating. Our Downstream Segment also includes our equity investment in Centennial.
Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or from third party pipeline systems, and arranging the necessary logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes the equity earnings from our investment in Seaway. Seaway is a large diameter pipeline that transports crude oil from the U.S. Gulf Coast to Cushing, a central crude oil distribution point for the Central United States.
Our Midstream Segment revenues are earned from the gathering of natural gas, fractionation of NGLs and transportation of NGLs. The Midstream Segment includes the operations from the acquisition of Jonah on September 30, 2001, from Alberta Energy Company for $359.8 million. We paid an additional $7.3 million on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. The results of operations of the acquisition are included in our consolidated financial statements beginning in the fourth quarter of 2001. The Jonah assets are managed and operated by DEFS under a contractual agreement.
On March 1, 2002, we completed the purchase of the Chaparral NGL system for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition related costs of approximately $0.4 million. The Chaparral NGL system has an 800-mile pipeline that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. The Chaparral NGL system also has an approximately 170-mile NGL gathering system located in West Texas, which begins in Sutton County, Texas, and connects to the 800-mile pipeline near Midland. The pipelines are connected to 27 gas plants in West Texas and have approximately 28,000 horsepower of pumping capacity at 14 stations. The Chaparral NGL system is managed and operated by DEFS under a contractual agreement. These assets are included in the Midstream Segment.
On June 30, 2002, we completed the purchase of the Val Verde Gathering System for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition related costs of approximately $1.2 million. Val Verde gathers CBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system is one of the largest CBM gathering and treating facilities in the United States, gathering CBM from more than 540 separate wells throughout New Mexico. The system provides gathering and treating services pursuant to approximately 60 long-term contracts with approximately 40 different gas producers in the San Juan Basin. Gas gathered on the Val Verde Gathering System is delivered to several interstate pipeline systems serving the western United States and to local New Mexico markets. The Val Verde Gathering System consists of 360 miles of pipeline ranging in size from 4 inches to 36 inches in diameter, 14 compressor stations operating over 93,000 horsepower of compression and a large amine treating facility for the removal of carbon dioxide. The system has a pipeline capacity of approximately one billion cubic feet per day. The Val Verde assets are managed and operated by DEFS under a contractual agreement. These assets are included in the Midstream Segment.
Critical Accounting Policies
The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities in the accompanying financial statements. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Key estimates used by management include revenue and expense accruals, environmental costs, depreciation and amortization, asset impairment and fair values of assets acquired. Significant accounting policies that we employ are presented in the notes to the consolidated financial statements.
Critical accounting policies are those that are most important to the portrayal to our financial position and results of operations. These policies require management’s most difficult, subjective or complex judgments, often employing the use of estimates about the effect of matters that are inherently uncertain. Our most critical accounting policies pertain to revenue and expense accruals, environmental costs, property, plant and equipment, goodwill and intangible assets.
Revenue and Expense Accruals
We routinely make accruals for both revenues and expenses before we receive certain third party information and reconcile our records with those of third parties. The delayed information from third parties includes, among other things, actual volumes of crude oil purchased, transported or sold, adjustments to inventory and invoices for purchases and other operating expenses. We make accruals to reflect estimates for these items based on our internal records and information from third parties. The estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.
Environmental Costs
At December 31, 2002, we have accrued a liability for our estimate of the future payments we expect to pay for environmental costs to remediate existing conditions attributable to past operations. We accrue for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs, including direct internal and legal costs, is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations. For information concerning environmental regulation and environmental costs and contingencies, see Item 1 and 2. Business and Properties - “Environmental Matters” in this Report.
Property, Plant and Equipment
We record property, plant and equipment at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).
We evaluate impairment of long-lived assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of, and effective January 1, 2002, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. Estimates of future net cash flows include anticipated future revenues, expected future operating costs and other estimates. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.
During the second quarter of 2001, Pennzoil-Quaker State Company (“Pennzoil”) sold its Shreveport, Louisiana, refinery. Under its transportation agreement with TE Products, Pennzoil had a throughput commitment of 25,000 barrels per day. Pennzoil and TE Products negotiated a settlement of $18.9 million to terminate the long-term transportation agreement from the Shreveport origin point on the Products Pipeline System. The termination payment was recorded as refined products transportation revenue in 2001.
We have evaluated the impact of the contract termination on the pipeline segment from Shreveport to El Dorado, Arkansas, in accordance with SFAS 144. The evaluation did not result in an impairment of the carrying value of the related transportation assets, which was $28.1 million at December 31, 2002. We are pursuing various alternatives including making system changes to allow for bi-directional product flow to make deliveries into the Shreveport market area. We have completed feasibility studies, and we are in discussions with potential customers regarding the transportation of volumes through this pipeline. If alternative revenue sources are not realized on this pipeline segment, an impairment may be recorded for the excess of the carrying value over discounted future net cash flows.
Goodwill and Intangible Assets
Goodwill and intangible assets represent the excess of consideration paid over the fair value of tangible net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired including goodwill and other intangible assets as well as determining the allocation of goodwill to the appropriate reporting unit. In addition, we assess the recoverability of these intangibles by determining whether the amortization of these intangibles over their remaining useful lives can be recovered through undiscounted future net cash flows of the acquired operations. The amount of impairment, if any, is measured by the amount by which the carrying amounts exceed the projected discounted future operating cash flows. During 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the amortization of goodwill and indefinite life intangibles and requires an annual test of impairment based on a comparison of fair value to carrying values. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections resulting in revisions to our assumptions and, if required, recognizing an impairment loss. Based on our assessment, we do not believe our goodwill is impaired and we have not recorded a charge from the adoption of SFAS 142.
At December 31, 2002, we have $433.7 million of natural gas transportation contracts which were recorded as part of our acquisitions of Jonah on September 30, 2001, and Val Verde on June 30, 2002 (see Note 5. Acquisitions). The value assigned to the natural gas transportation contracts required management to make estimates regarding the fair value of the assets acquired. In connection with the acquisition of Jonah, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming. We assigned $222.8 million of the purchase price to these production contracts based upon a fair value appraisal at the time of closing. In connection with the acquisition of Val Verde, we assumed fixed-term gas transportation contracts with customers in the San Juan Basin in New Mexico and Colorado. We assigned $239.6 million of the purchase price to these fixed term contracts based upon a fair value appraisal at the time of the closing. The value assigned to intangible assets is amortized on a unit of production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. The amortization of the Jonah and Val Verde systems are expected to average approximately 16 years and 20 years, respectively. On a quarterly basis, we update production estimates of the natural gas wells and evaluate the remaining expected useful life of the contract assets. Changes in the estimated remaining production will impact the timing of amortization expense reported for future periods.
Results of Operations
The following table summarizes financial data by business segment (in thousands):
Below is a detailed analysis of the results of operations, including reasons for changes in results, by each of our operating segments.
Downstream Segment
The following table presents volume and average tariff information for the years ended December 31, 2002, 2001 and 2000:
(1)
Excludes $18.9 million received from Pennzoil for canceled transportation agreement discussed below.
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Our Downstream Segment reported earnings before interest of $77.1 million for the year ended December 31, 2002, compared with earnings before interest of $118.1 million for the year ended December 31, 2001. Earnings before interest decreased $41.0 million primarily due to a decrease of $20.7 million in operating revenues, an increase of $13.9 million in costs and expenses, additional losses of $5.7 million from equity investments and a decrease of $0.7 million in other income - net. We discuss the factors influencing these variances below.
Revenues from refined products transportation decreased $15.8 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to $18.9 million of revenue recognized in 2001 from a cash settlement received from a canceled transportation agreement with Pennzoil and the recognition of $1.7 million of previously deferred revenue related to the approval of market-based rates during the second quarter of 2001. See further discussion regarding these factors included in “Other Considerations.” These decreases were partially offset by a 12% increase in refined products volumes delivered during the year ended December 31, 2002, primarily due to barrels received into our pipeline from Centennial at Creal Springs, Illinois. Centennial commenced refined products deliveries to us beginning in April 2002. The overall increase in refined products deliveries was partially offset by a 1.3 million barrel decrease in MTBE deliveries as a result of the expiration of contract deliveries to our marine terminal near Beaumont effective April 2001. As a result of the contract expiration, we no longer transport MTBE through our Products Pipeline System. The refined products average rate per barrel decreased 9% from the prior year due to the impact of the Midwest origin point for volumes received from Centennial, which was partially offset by decreased short-haul MTBE volumes delivered, and higher market-based tariff rates, which went into effect in July 2001.
Revenues from LPGs transportation decreased $3.2 million for the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to decreased deliveries of propane in the upper Midwest and Northeast market areas attributable to warmer than normal weather in the first quarter of 2002. The decrease was also due to lower prices from competing Canadian and mid-continent propane supply as compared to propane originating from the Gulf Coast. Total LPGs volumes delivered increased 1% as a result of increased short-haul deliveries to a petrochemical facility on the upper Texas Gulf Coast. The LPGs average rate per barrel decreased 6% from the prior year as a result of a decreased percentage of long-haul deliveries during the year ended December 31, 2002.
Revenues generated from Mont Belvieu operations increased $1.1 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, as a result of increased storage revenue and receipt revenue. Mont Belvieu shuttle volumes delivered increased 25% during the year ended December 31, 2002, compared with the year ended December 31, 2001, due to increased petrochemical demand. The Mont Belvieu average rate per barrel decreased 17% during the year ended December 31, 2002, as a result of increased contract shuttle deliveries, which generally carry lower rates.
Other operating revenues decreased $2.8 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to lower propane deliveries from our Providence import facility, lower refined products storage revenue, lower margins on product inventory sales and lower revenues from product location exchanges which are used to position product in the Midwest market area. These decreases were partially offset by increased refined products and LPGs loading fees.
Costs and expenses increased $13.9 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. The increase was comprised of an increase of $11.8 million in operating, general and administrative expenses, an increase of $3.4 million in depreciation and amortization expense and an increase of $3.1 million in taxes - other than income taxes. These increases were partially offset by a decrease of $4.4 million in operating fuel and power expense. Operating, general and administrative expenses increased primarily due to higher pipeline maintenance expenses, increased consulting and contract services, increased labor costs and increased general and administrative supplies expense. Depreciation expense increased from the prior year because of assets placed in service during 2002. Taxes - other than income taxes increased as a result of a higher property base in 2002. Operating fuel and power expense decreased as a result of decreased long-haul volumes delivered related to Midwest volumes received from Centennial and lower power costs.
Net losses from equity investments totaled $6.8 million during the year ended December 31, 2002, due to pre-operating expenses and start-up costs of Centennial, which commenced operations in early April 2002.
Other income - net decreased $0.7 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. The decrease was primarily due to lower interest income earned on cash investments.
The Downstream Segment is dependent in large part on the demand for refined petroleum products in the markets served by its pipelines. Reductions in that demand adversely affect the pipeline business of the Downstream Segment. Market demand varies based upon the different end uses of the refined products shipped in the Downstream Segment. Demand for gasoline, which in recent years has accounted for approximately one-half of the Downstream Segment’s refined products transportation revenues, depends upon price, prevailing economic conditions and demographic changes in the markets served in the Downstream Segment. Weather conditions and governmental policy affect the demand for refined products used in agricultural operations. Demand for jet fuel, which in recent years has accounted for approximately one-quarter of the Downstream Segment’s refined products revenues, depends on prevailing economic conditions and military usage. Propane deliveries are generally sensitive to the weather and meaningful year-to-year variances have occurred and will likely continue to occur.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Our Downstream Segment reported earnings before interest of $118.1 million for the year ended December 31, 2001, compared with earnings before interest of $87.1 million for the year ended December 31, 2000. Earnings before interest increased $31.0 million primarily due to an increase of $35.0 million in operating revenues, partially offset by an increase of $2.8 million in costs and expenses, additional losses of $1.1 million from equity investments and a decrease of $0.1 million in other income - net. We discuss the factors influencing these variances below.
Revenues from refined products transportation increased $20.0 million for the year ended December 31, 2001, compared with the year ended December 31, 2000, primarily due to $18.9 million of revenue recognized on the canceled transportation agreement with Pennzoil in 2001 and the recognition of $1.7 million of previously deferred revenue related to the approval of market-based rates during the second quarter of 2001. These increases were partially offset by a 4% decrease in refined products volumes delivered. Deliveries of MTBE decreased 4.3 million barrels as a result of the expiration of contract deliveries to our marine terminal near Beaumont in April
2001. Jet fuel volumes decreased 2.7 million barrels, or 10%, due to reduced air travel demand in the Midwest market areas. The total refined products volume decrease was partially offset by increased distillate demand in the South-Central market areas and increased distillate deliveries at a third-party terminal in Houston, Texas. The refined products average rate per barrel increased 5% from the prior-year period primarily due to an increased percentage of long-haul volumes delivered in 2001.
Revenues from LPGs transportation increased $3.9 million for the year ended December 31, 2001, compared with the year ended December 31, 2000, primarily due to increased propane deliveries in the Midwest that resulted from favorable price differentials of Gulf Coast propane compared with competing Midwest supply sources. Additionally, increased feedstock demand resulted in higher deliveries of isobutane in the Chicago market area. Short-haul deliveries of propane along the upper Texas Gulf Coast decreased 29% from the prior year due to lower petrochemical feedstock demand and operational problems at a petrochemical facility that we serve. The LPGs average rate per barrel increased 5% from the prior year as a result of an increased percentage of long-haul deliveries to the upper Midwest market areas.
Revenues generated from Mont Belvieu operations increased $0.8 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, as a result of increased loading fees, brine service revenue and butane segregation charges, partially offset by lower contract storage revenue. Mont Belvieu shuttle deliveries decreased 15% during the year ended December 31, 2001, compared with the year ended December 31, 2000, due to reduced propane and butane demand for petrochemical feedstock along the upper Texas Gulf Coast. The Mont Belvieu average rate per barrel increased in 2001 as a result of increased non-contract deliveries, which generally carry higher rates.
Other operating revenues increased $10.3 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, primarily due to an increase of $8.9 million in contract petrochemical delivery revenue, which began during the fourth quarter of 2000, increased refined products loading fees, increased propane deliveries from the Providence import facility and increased gains on product sales. These increases were partially offset by lower revenues from product location exchanges which are used to position product in the Midwest market area.
Costs and expenses increased $2.8 million for the year ended December 31, 2001, compared with the year ended December 31, 2000, and were comprised of an increase of $2.1 million in operating, general and administrative expenses, an increase of $1.2 million in operating fuel and power expense and an increase of $1.0 million in depreciation and amortization expense, partially offset by a decrease of $1.5 million in taxes - other than income taxes. The increase in operating, general and administrative expenses was primarily due to increased employee benefit costs, increased supplies and services and environmental remediation expenses, partially offset by the March 2000 write-off of project evaluation costs related to the proposed pipeline construction from Beaumont to Little Rock, Arkansas, and decreased product measurement losses. Operating fuel and power expense increased as a result of higher rates charged by electric utilities and increased long-haul volumes delivered. The increase in depreciation expense from the prior year period resulted from assets placed in service during the fourth quarter of 2000. The decrease in taxes - other than income taxes resulted from actual property taxes being lower than previously estimated.
Net losses from equity investments totaled $1.1 million during the year ended December 31, 2001, due primarily to pre-operating expenses of Centennial.
Other income - net decreased $0.1 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, primarily due to lower interest income earned on cash investments.
Upstream Segment
We calculate the margin of the Upstream Segment as revenues generated from the sale of crude oil and lubrication oil, and transportation of crude oil, less the costs of purchases of crude oil and lubrication oil. Margin is a more meaningful measure of financial performance than operating revenues and operating expenses due to the significant fluctuations in revenues and expenses caused by variations in the level of marketing activity and prices
for products marketed. Margin and volume information for the years ended December 31, 2002, 2001 and 2000 is presented below (in thousands, except per barrel and per gallon amounts):
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Our Upstream Segment reported earnings before interest of $46.7 million for the year ended December 31, 2002, compared with earnings before interest of $38.0 million for the year ended December 31, 2001. Earnings before interest increased $8.7 million primarily due to an increase of $6.0 million in margin, a decrease of $2.9 million in costs and expenses (excluding purchases of crude oil and lubrication oil), an increase of $0.3 million in other income - net and an increase of $0.2 million in equity earnings of Seaway. These increases were partially offset by a decrease of $0.7 million in other operating revenues. We discuss the factors influencing these variances below.
Our margin increased $6.0 million during the year ended December 31, 2002, compared with the year ended December 31, 2001. Crude oil transportation margin increased $4.9 million primarily due to volumes transported on the pipeline assets acquired from Valero in March 2001 and higher revenues on our Basin, Red River and West Texas systems. Crude oil terminaling margin remained constant between years as a result of higher volumes at Midland and our Red River system, offset by lower volumes at Cushing and on our Basin system. Lubrication oil sales margin increased $0.7 million due to increased volumes related to the acquisition of a lubrication oil distributor in Amarillo, Texas, in the fourth quarter of 2001. Crude oil marketing margin increased $0.4 million primarily due to increased volumes marketed, renegotiated supply contracts and lower trucking expenses.
Other operating revenues of the Upstream Segment decreased $0.7 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, due to lower revenues from documentation and other services to support customers’ trading activity at Midland and Cushing.
Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, decreased $2.9 million during the year ended December 31, 2002, compared with the year ended December 31, 2001. Operating, general and administrative expenses decreased $3.8 million from the prior year due to $4.4 million of environmental costs recognized in 2001 and decreased labor related costs, partially offset by increased general and administrative supplies and services expense and environmental costs recognized in 2002, primarily related to the Shelby site (see Note 17. Commitments and Contingencies in Notes to the Consolidated Financial Statements). Depreciation and amortization expense increased $1.9 million due to increased depreciation expense on the assets
acquired from Valero and from the acquisition of a lubrication oil distributor in Amarillo, Texas, partially offset by lower amortization costs from the adoption of SFAS 142 effective January 1, 2002, in which goodwill and excess investment are no longer being amortized. Taxes - other than income taxes decreased $1.6 million due to reductions in property tax accruals. These decreases were partially offset by an increase of $0.6 million in operating fuel and power costs attributed to higher transportation volumes.
Equity earnings in Seaway for the year ended December 31, 2002, increased $0.2 million from the year ended December 31, 2001, due to higher third party transportation volumes. This increase was partially offset by our portion of equity earnings being reduced from 80% to 60% on a pro rated basis in 2002 (averaging approximately 67% for the year ended December 31, 2002). Equity earnings in Seaway were affected in 2002 as a result of the reduction of the sharing percentages of TCTM under the Seaway partnership agreement. Beginning in June 2002, our participation in Seaway decreased from 80% of revenue and expense of Seaway to 60%. See Items 1 and 2. Business and Properties, “Upstream Segment - Gathering, Transportation, Marketing and Storage of Crude Oil” for a more detailed discussion.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Our Upstream Segment reported earnings before interest of $38.0 million for the year ended December 31, 2001, compared with earnings before interest of $26.4 million for the year ended December 31, 2000. Earnings before interest increased $11.6 million primarily due to an increase of $25.1 million in margin, an increase of $6.4 million in other operating revenues, an increase of $6.3 million in equity earnings of Seaway and an increase of $1.7 million in other income - net. These increases were partially offset by an increase of $27.9 million in costs and expenses (excluding purchases of crude oil and petroleum products). We discuss the factors influencing these variances below.
Our margin increased $25.1 million during the year ended December 31, 2001, compared with the year ended December 31, 2000. Crude oil transportation margin increased $10.8 million primarily due to a full year benefit from the ARCO assets acquired in July 2000 and higher volumes on the Red River and South Texas systems, which benefited from increased regional crude oil production and pipeline assets acquired from Valero in March 2001. Crude oil marketing margin increased $8.3 million primarily due to volumes transported by Seaway on behalf of the Upstream Segment. The transportation revenues associated with these volumes resulted in $10.1 million included as a component of crude oil marketing margin when consolidating the Upstream Segment’s equity ownership in Seaway. Lower margins on other crude oil volumes marketed partially offset the increase in crude oil marketing margin. Crude oil terminaling margin increased $5.2 million as a result of pumpover volumes at Midland and Cushing, related to the ARCO assets acquired in July 2000. Margin contributed from lubrication oil sales increased $0.6 million primarily due to increased volumes and increased rates on the margin realized per gallon.
Other operating revenue of the Upstream Segment increased $6.4 million during the year ended December 31, 2001, compared with the year ended December 31, 2000. The increase is attributable to revenue from documentation and other services to support customer trading activity at Midland and Cushing. These revenues were added to our business on July 20, 2000, with the acquired ARCO assets.
Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $27.9 million during the year ended December 31, 2001, compared with the year ended December 31, 2000. The increase was comprised of an increase of $20.5 million in operating, general and administrative expenses, an increase of $3.0 million in depreciation and amortization expense, an increase of $3.9 million in taxes - other than income taxes and an increase of $0.6 million in operating fuel and power expense. The increase in operating, general and administrative expenses was primarily attributable to operating expenses of the acquired assets from ARCO, DEFS and Valero, $4.4 million of expense recorded in 2001 for environmental remediation, increased labor related costs and increased general and administrative supplies and services expense. The increases in depreciation and amortization expense, taxes - other than income taxes and operating fuel and power expense were primarily attributable to assets acquired.
Equity earnings in Seaway increased $6.3 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, due to the full year contribution to earnings during 2001.
Midstream Segment
The following table presents volume and average rate information for the years ended December 31, 2002, 2001 and 2000:
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Our Midstream Segment reported earnings before interest of $61.0 million for the year ended December 31, 2002, compared with earnings before interest of $15.9 million for the year ended December 31, 2001. Earnings before interest increased $45.1 million due to an increase of $101.6 million in operating revenues and an increase of $0.3 million in other income - net, partially offset by an increase of $56.8 million in costs and expenses. We discuss the factors influencing these variances below.
Operating revenues increased $101.6 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, due to an increase of $81.2 million in natural gas gathering revenues, an increase of $18.2 million in NGL transportation revenues and an increase of $2.2 million in other revenues. Natural gas gathering revenues from the Jonah system increased $41.3 million and volumes delivered increased 202.9 billion cubic feet during the year ended December 31, 2002, due to a full year’s contribution to earnings from Jonah in 2002. The Jonah system was acquired on September 30, 2001. Natural gas gathering revenues from the Val Verde system, which was acquired on June 30, 2002, totaled $39.9 million and volumes delivered totaled 92.3 billion cubic feet during the year ended December 31, 2002. Other revenues increased $2.2 million primarily due to sales of gas condensate from the Jonah system. NGL transportation revenues increased $18.2 million, primarily due to the acquisition of the Chaparral NGL system on March 1, 2002, partially offset by lower revenues on a take-or-pay contract on the Dean pipeline system that was in effect until the bankruptcy of Enron Corp. in December 2001. The decrease in the NGL transportation average rate per barrel resulted from the cancellation of the Enron Corp. take-or-pay contract and a lower average rate per barrel on volumes transported on Chaparral.
Costs and expenses increased $56.8 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, due to an increase of $34.8 million in depreciation and amortization expense, an increase of $15.5 million in operating, general and administrative expense, an increase of $4.1 million in operating fuel and power costs and an increase of $2.4 million in taxes - other than income taxes. Depreciation and amortization expense increased $34.6 million due to the Jonah, Chaparral and Val Verde assets acquired on September 30, 2001, March 1, 2002, and June 30, 2002, respectively. Operating, general and administrative
expense increased $15.5 million due to an increase of $17.6 million from assets acquired, an increase of $2.2 million attributable to higher general and administrative labor and supplies expense, partially offset by decreased operating expenses. Operating, general and administrative expenses for the year ended December 31, 2001, included a $4.3 million reserve for a doubtful receivable balance under a transportation contract with an Enron Corp. subsidiary. Operating fuel and power costs and taxes - other than income taxes increased $4.1 million and $2.4 million, respectively, due to the assets acquired in 2001 and 2002.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Our Midstream Segment reported earnings before interest of $15.9 million for the year ended December 31, 2001, compared with earnings before interest of $9.1 million for the year ended December 31, 2000. Earnings before interest increased $6.8 million due to an increase of $22.8 million in operating revenues, partially offset by an increase of $15.8 million in costs and expenses and a decrease of $0.2 million in other income - net. We discuss the factors influencing these variances below.
Operating revenues increased $22.8 million during the year ended December 31, 2001, compared with the year ended December 31, 2000. Operating revenues for the year ended December 31, 2001, for Jonah were $9.1 million. Natural gas gathering revenues totaled $8.8 million from volumes delivered of 45.5 billion cubic feet. An additional $0.3 million was generated from the sale of 16,180 barrels of condensate liquid to an Upstream Segment marketing affiliate. Other revenues increased $0.3 million due to sales of gas condensate from the Jonah system, which was acquired on September 30, 2001. NGL transportation revenues increased $13.7 million primarily due to the acquisition of the Panola system on December 31, 2000, partially offset by decreased volumes on the Dean pipeline system in South Texas.
Costs and expenses increased $15.8 million during the year ended December 31, 2001, compared with the year ended December 31, 2000. Costs and expenses for Jonah were $6.0 million and were comprised of $4.5 million of depreciation and amortization expense, $1.4 million of operating, general and administrative expense and $0.1 million of taxes - other than income taxes. Costs and expenses also included $4.1 million due to the acquisition of the Panola system on December 31, 2000, comprised of $1.4 million of operating, general and administrative expense, $2.2 million of depreciation and amortization expense and $0.5 million of taxes - other than income taxes. The increase in costs and expenses also included a $4.3 million reserve for a doubtful receivable balance under a transportation contract with an Enron Corp. subsidiary. The remaining increase was due to increased labor related costs and increased general and administrative supplies and services expense.
Interest Expense and Capitalized Interest
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
Interest expense increased $4.5 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, primarily due to higher outstanding debt balances used for capital expenditures and to finance the acquisition of assets acquired in the Midstream Segment, partially offset by lower LIBOR rates in effect during the year ended December 31, 2002.
Capitalized interest increased $0.3 million during the year ended December 31, 2002, compared with the year ended December 31, 2001, due to interest capitalized on the investment during the construction of the Jonah expansion and increased balances during 2002 on construction work-in-progress.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Interest expense increased $17.1 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, primarily due to higher outstanding debt balances used to finance the acquisition of assets acquired in the Midstream and Upstream Segments. These increases were partially offset by lower interest
rates on borrowings under the variable-rate credit facilities and the favorable impact of the fixed-to-floating interest rate swap on the TE Products Senior Notes, effective October 4, 2001.
Capitalized interest decreased $0.6 million during the year ended December 31, 2001, compared with the year ended December 31, 2000, due to the completion of the petrochemical pipelines from Mont Belvieu to Port Arthur during the fourth quarter of 2000. This decrease was partially offset by increased balances on construction work-in-progress in the Upstream and Midstream Segments.
Financial Condition and Liquidity
Net cash from operations totaled $234.9 million for the year ended December 31, 2002. This cash was made up of $203.9 million of income before charges for depreciation and amortization and $31.0 million of cash provided by working capital changes. This compares with net cash from operations of $169.2 million for the year ended December 31, 2001, comprised of $155.0 million of income before charges for depreciation and amortization and $14.2 million of cash provided by working capital changes. Net cash from operations for the year ended December 31, 2000, totaled $108.0 million and was comprised of $112.5 million of income before charges for depreciation and amortization, partially offset by $4.5 million of cash used for working capital charges. Net cash from operations for the years ended December 31, 2002, 2001 and 2000 included interest payments of $48.9 million, $61.5 million and $36.8 million, respectively.
Cash flows used in investing activities totaled $724.7 million during the year ended December 31, 2002, and were comprised of $7.3 million for the final purchase price adjustments on the acquisition of Jonah, $133.4 million of capital expenditures, $10.9 million of cash contributions for our ownership interest in Centennial, $132.4 million for the purchase of the Chaparral NGL system on March 1, 2002, and $444.2 million for the purchase of Val Verde on June 30, 2002. These uses of cash were partially offset by $3.5 million in cash proceeds from the sale of assets. Cash flows used in investing activities totaled $557.9 million during the year ended December 31, 2001, and were comprised of $359.8 million for the purchase of Jonah on September 30, 2001, $107.6 million of capital expenditures, $65.0 million of cash contributions for our ownership interest in Centennial, $20.0 million for the purchase of assets from Valero on March 1, 2001, and $11.0 million paid in October 2001, for the final purchase price settlement related to the previously acquired ARCO assets. These uses of cash were partially offset by $1.3 million of cash received from the sale of vehicles and $4.2 million received on matured cash investments. Cash flows used in investing activities totaled $494.2 million during the year ended December 31, 2000, and were comprised of $322.6 million for the purchase of the ARCO assets, $99.5 million for the purchase of NGL and crude oil systems in East Texas and North Texas, $68.5 million of capital expenditures, $5.0 million of cash contributions for our ownership interest in Centennial and $2.0 million of cash investments. These uses of cash were partially offset by $3.4 million received from matured cash investments. Capital expenditures during the year ended December 31, 2000, included $29.9 million of spending for construction of the petrochemical pipelines between our terminals in Mont Belvieu and Port Arthur.
Cash flows provided by financing activities totaled $495.3 million during the year ended December 31, 2002, and were comprised of $675.0 million in proceeds from term and revolving credit facilities; $497.8 million from the issuance in February 2002 of our 7.625% Senior Notes due 2012, partially offset by debt issuance costs of $7.0 million; $372.5 million from the issuance of 13.4 million Limited Partner Units during the year ended December 31, 2002, and $7.6 million of related General Partner contributions; and $44.9 million of proceeds from the termination of our interest rate swaps on our 7.625% Senior Notes due 2012. These sources of cash during the year ended December 31, 2002, were partially offset by $943.7 million of repayments on our term and revolving credit facilities and $151.8 million of distributions to Limited Partner unitholders. Cash flows provided by financing activities totaled $387.1 million during the year ended December 31, 2001, and were comprised of $546.1 million of proceeds from term and revolving credit facilities, partially offset by debt issuance costs of $2.6 million; and $234.7 million from the issuance of 7.8 million Limited Partner Units during the year ended December 31, 2001, and $4.8 million of related General Partner contributions. These sources of cash during the year ended December 31, 2001 were partially offset by $291.5 million of repayments on our term and revolving credit facilities and $104.4 million of distributions to Limited Partner unitholders. Cash flows provided by financing activities totaled $380.7 million during the year ended December 31, 2000, and were comprised of $552.0 million in proceeds from term and
revolving credit facilities, partially offset by debt issuance costs of $7.1 million; and $88.2 million from the issuance of 3.7 million Limited Partner Units during the year ended December 31, 2000, and $1.8 million of related General Partner contributions. These sources of cash during the year ended December 31, 2000, were partially offset by $172.0 million of repayments on our term and revolving credit facilities and $82.2 million of distributions to Limited Partner unitholders.
In August 2000, TE Products entered into agreements with PEPL and Marathon to form Centennial. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. During the years ended December 31, 2002 and 2001, TE Products contributed approximately $10.9 million and $70.0 million, respectively, for its investment in Centennial. These amounts are included in our equity investment balance at December 31, 2002 and 2001. Through February 9, 2003, each original participant owned a one-third interest in Centennial. On February 10, 2003, TE Products and Marathon each acquired an additional 16.7% interest in Centennial, bringing their ownership interest to 50% each. Excluding TE Products’ purchase of its additional ownership interest of 16.7% on February 10, 2003, we expect to contribute an additional $10.0 million to Centennial in 2003.
Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2002, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. Each of the participants in Centennial, including TE Products, originally guaranteed one-third of Centennial’s debt, up to a maximum amount of $50.0 million. During the third quarter of 2002, PEPL, one of the participants in Centennial, was downgraded by Moody’s and Standard & Poors to below investment grade, which resulted in PEPL being in default under its portion of the Centennial guaranty. Effective September 27, 2002, TE Products and Marathon increased their guaranteed amounts to one-half of the debt of Centennial, up to a maximum amount of $75.0 million each, to avoid a default on the Centennial debt. As compensation to TE Products and Marathon for providing their additional guarantees, PEPL was required to pay interest at a rate of 4% per annum to each of TE Products and Marathon on the portion of the additional guaranty that each had provided for PEPL. In connection with the acquisition of the additional interest in Centennial on February 10, 2003, the guaranty agreement between TE Products, Marathon and PEPL was terminated. TE Products’ guaranty of up to a maximum of $75.0 million of Centennial’s debt remains in effect.
In February 2000, we entered into a joint marketing and development alliance with Louis Dreyfus in which our Mont Belvieu LPGs storage and transportation shuttle system services were jointly marketed by Louis Dreyfus and TE Products. The purpose of the alliance was to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. The alliance was a service-oriented, fee-based venture with no commodity trading activity. TE Products operated the facilities for the alliance. Under the alliance, Louis Dreyfus invested $6.1 million for expansion projects at Mont Belvieu. The alliance also stipulated that if certain earnings thresholds were achieved, a partnership between TE Products and Louis Dreyfus was to be created effective January 1, 2003. All terms and earnings thresholds have been met; therefore, we will be contributing our Mont Belvieu assets to the newly formed partnership. The economic terms of the partnership are the same as those under the joint development and marketing alliance. TE Products will continue to operate the facilities for the partnership. The net book value of the Mont Belvieu assets that we are contributing to the partnership is approximately $68.2 million. Our interest in the partnership will be accounted for as an equity investment.
Credit Facilities and Interest Rate Swap Agreements
On July 14, 2000, we entered into a $75.0 million term loan and $475.0 million revolving credit facility (“Three Year Facility”). On July 21, 2000, we borrowed $75.0 million under the term loan and $340.0 million under the Three Year Facility. The funds were used to finance the acquisition of the ARCO assets and to refinance existing bank credit facilities, other than the Senior Notes. The term loan was repaid from proceeds received from the issuance of additional Limited Partner Units on October 25, 2000. On April 6, 2001, the Three Year Facility was amended to provide for revolving borrowings of up to $500.0 million for a period of three years including the issuance of letters of credit of up to $20.0 million. The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contains restrictive financial covenants that require us to maintain a minimum level of partners’
capital as well as maximum debt-to-EBITDA (earnings before interest expense, income tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. On February 20, 2002, we repaid $115.7 million of the then outstanding balance of the Three Year Facility with proceeds from the issuance of our 7.625% Senior Notes. On March 1, 2002, we borrowed $132.0 million under the Three Year Facility to finance the acquisition of the Chaparral NGL system. On March 22, 2002, we repaid a portion of the Three Year Facility with proceeds we received from the issuance of additional Limited Partner Units (see Note 11. Partners’ Capital). To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Three Year Facility was amended to increase the maximum permitted debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. For the twelve month period ending June 30, 2002, the maximum permitted ratio was 5.5-to-1 on a pro forma basis. For the twelve month period ending September 30, 2002, the maximum permitted ratio was 5.0-to-1 on a pro forma basis. At December 31, 2002, the maximum permitted debt-to-EBITDA ratio under our revolving credit facility returned to its pre-amendment level of 4.5-to-1. We then drew down the existing capacity of the Three Year Facility and acquired the Val Verde assets. During the fourth quarter of 2002, we repaid $68.0 million of the outstanding balance of the Three Year Facility with proceeds from our November 2002 equity offering and proceeds from the termination of our interest rate swaps. At December 31, 2002, $432.0 million was outstanding under the Three Year Facility at a weighted average interest rate of 2.5%. As of December 31, 2002, we were in compliance with the covenants contained in this credit agreement.
On April 6, 2001, we entered into a 364-day, $200.0 million revolving credit agreement (“Short-term Revolver”). The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On March 28, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in March 2003. To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Short-term Revolver was amended to increase the maximum debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. For the twelve month period ending June 30, 2002, the maximum permitted ratio was 5.5-to-1 on a pro forma basis. For the twelve month period ending September 30, 2002, the maximum permitted ratio was 5.0-to-1 on a pro forma basis. At December 31, 2002, the maximum permitted debt-to-EBITDA ratio under our revolving credit facility returned to its pre-amendment level of 4.5-to-1. We then drew down $72.0 million under the Short-term Revolver. In the fourth quarter of 2002, we repaid the existing amounts outstanding under the Short-term Revolver with proceeds we received from the issuance of Limited Partner Units in November and December 2002. At December 31, 2002, no amounts were outstanding under the Short-term Revolver. As of December 31, 2002, we were in compliance with the covenants contained in this credit agreement. In February 2003, we gave notice that we will not renew the Short-term Revolver. As a result, the facility will expire on March 27, 2003.
On September 28, 2001, we entered into a $400.0 million credit facility with SunTrust Bank (“Bridge Facility”) payable in June 2002. We borrowed $360.0 million under the Bridge Facility to acquire the Jonah assets (see Note 5. Acquisitions). During the fourth quarter of 2001, we repaid $160.0 million of the outstanding principal from proceeds received from the issuance of Limited Partner Units in November 2001. On February 5, 2002, we drew down an additional $15.0 million under the Bridge Facility. On February 20, 2002, we repaid the outstanding balance of the Bridge Facility of $215.0 million with proceeds from the issuance of the 7.625% Senior Notes and canceled the facility.
On February 20, 2002, we received $494.6 million in net proceeds, after underwriting discount, from the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, described above, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing the 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2002, we were in compliance with the covenants of these Senior Notes.
On June 27, 2002, we entered into a $200.0 million six-month term loan with SunTrust Bank (“Six-Month Term Loan”) payable in December 2002. We borrowed $200.0 million under the Six-Month Term Loan to acquire the Val Verde assets (see Note 5. Acquisitions). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained restrictive financial covenants that required us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On July 11, 2002, we repaid $90.0 million of the outstanding principal from proceeds primarily received from the issuance of Limited Partner Units in July 2002. On September 10, 2002, we repaid the remaining outstanding balance of $110.0 million with proceeds received from the issuance of Limited Partner Units in September 2002 (see Note 11. Partners’ Capital) and canceled the facility.
On January 30, 2003, we received $197.3 million in net proceeds, after underwriting discount, from the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and will be accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on the Three Year Facility to $250.0 million. The balance of the proceeds of $15.3 million was used for general purposes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness.
The following table summarizes our credit facilities as of December 31, 2002 (in millions):
Distributions and Issuance of Additional Limited Partner Units
We paid cash distributions of $151.9 million ($2.35 per Unit), $104.4 million ($2.15 per Unit) and $82.2 million ($2.00 per Unit), during each of the years ended December 31, 2002, 2001 and 2000, respectively. Additionally, on January 16, 2003, we declared a cash distribution of $0.60 per Limited Partner Unit and Class B
Unit for the quarter ended December 31, 2002. The distribution of $46.5 million was paid on February 7, 2003, to unitholders of record on January 31, 2003.
On February 6, 2001, we sold in an underwritten public offering 2.0 million Limited Partner Units at $25.50 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $48.7 million and were used to reduce borrowings under the Three Year Facility. On March 6, 2001, 250,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on February 6, 2001. Proceeds from that sale totaled $6.1 million and were used for general purposes.
On November 14, 2001, we sold in an underwritten public offering 5.5 million Limited Partner Units at $34.25 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $180.3 million and were used to repay $160.0 million under the Bridge Facility that was used to fund the Jonah acquisition. The remaining proceeds were used to finance contributions to Centennial and for other capital expenditures.
On March 22, 2002, we sold in an underwritten public offering 1.92 million Limited Partner Units at $31.18 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $57.3 million and were used to repay $50.0 million of the outstanding balance on the Three Year Facility, with the remaining amount being used for general purposes.
On July 11, 2002, we sold in an underwritten public offering 3.0 million Limited Partner Units at $30.15 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $86.6 million and were used to reduce borrowings under our Six-Month Term Loan. On August 14, 2002, 175,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on July 11, 2002. Proceeds from that sale totaled $5.1 million and were used for general purposes.
On September 6, 2002, we sold in an underwritten public offering 3.8 million Limited Partner Units at $29.72 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $108.1 million and were used to reduce borrowings under our Six-Month Term Loan. On September 19, 2002, 570,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on September 6, 2002. Proceeds from that sale totaled $16.2 million and were used to reduce borrowings under our Short-term Revolver.
On November 7, 2002, we sold in an underwritten public offering 3.3 million Limited Partner Units at $26.83 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $84.8 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility. On December 4, 2002, 495,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on November 7, 2002. Proceeds from that sale totaled $12.7 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility.
Future Capital Needs and Commitments
We estimate that capital expenditures, excluding acquisitions, for 2003 will be approximately $55.0 million (which includes $3.6 million of capitalized interest). We expect to use approximately $18.4 million for revenue generating projects. Capital spending on revenue generating projects will include approximately $7.5 million for the expansion of our pumping capacity of LPGs into the Northeast markets, approximately $1.9 million for expansion of our Downstream Segment’s deliverability capacity, $4.0 million to expand Upstream Segment facilities and approximately $5.0 million for the expansion of Midstream assets. We expect to spend approximately $26.0 million to sustain existing operations, of which approximately $19.3 million will be for Downstream Segment pipeline projects, including the replacement of storage tanks, pipeline rehabilitation projects to comply with regulations enacted by the OPS and the installation of replacement electrical distribution facilities at our Mont Belvieu facilities, $4.8 million for upgrades of our Upstream Segment and $1.9 million of capital expenditures to sustain existing operations on the Midstream Segment. An additional $7.0 million will be expended on system upgrade projects among all of our business segments. We continually review and evaluate potential capital improvements and expansions that would be complementary to our present business segments. These expenditures can vary greatly depending on the magnitude of our transactions. We may finance capital expenditures through internally generated funds, debt or the issuance of additional equity.
As of December 31, 2002, we had a working capital deficit of $6.2 million. In the event of any working capital shortfalls, we have approximately $68.0 million in available borrowing capacity under our Three Year Facility to cover these items.
Our debt repayment obligations consist of payments for principal and interest on (i) outstanding principal amounts under the Three Year Facility due in April 2004 ($432.0 million outstanding at December 31, 2002), (ii) the TE Products Senior Notes, $180.0 million principal amount due January 15, 2008, and $210.0 million principal amount due January 15, 2028, and (iii) our $500.0 million 7.625% Senior Notes due February 15, 2012.
TE Products is contingently liable as guarantor for the lesser of one-half or $75.0 million principal amount (plus interest) of the borrowings of Centennial. We expect to contribute an additional $10.0 million to Centennial in 2003 to provide for its working capital needs. In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years. On February 10, 2003, we acquired an additional 16.7% ownership interest in Centennial, bringing our ownership percentage to 50%.
We do not rely on off-balance sheet borrowings to fund our acquisitions. We have no off-balance sheet commitments for indebtedness other than the limited guaranty of Centennial debt and leases covering assets utilized in several areas of our operations.
The following table summarizes our debt repayment obligations and material contractual commitments as of December 31, 2002 (in millions):
We expect to repay the long-term, senior unsecured obligations and bank debt through the issuance of additional long-term senior unsecured debt at the time the 2008, 2012 and 2028 debt matures, issuance of additional equity, proceeds from dispositions of assets, cash flow from operations or any combination of the above items.
Sources of Future Capital
Historically, we have funded our capital commitments from operating cash flow and borrowings under bank credit facilities or bridge loans. We repaid these loans in part by the issuance of long term debt in capital markets and the public offering of Limited Partner Units. We expect future capital needs would be similarly funded to the extent not otherwise available from cash flow from operations.
As of December 31, 2002, we had approximately $268.0 million in combined available borrowing capacity under the Three Year Facility and the Short-term Revolver. In February 2003, we gave notice that we will not renew the Short-term Revolver. As a result, the Short-term Revolver will expire on March 27, 2003.
We expect that cash flows from operating activities will be adequate to fund cash distributions and capital additions necessary to sustain existing operations. However, expansionary capital projects and acquisitions may require funding through proceeds from the sale of additional debt or equity capital markets offerings.
On May 29, 2002, Moody’s Investors Service downgraded our senior unsecured debt rating to Baa3 from Baa2. Our subsidiary, TE Products was also included in this downgrade. These ratings were given with stable outlooks and followed our announcement of the acquisition of Val Verde. The downgrades reflect Moody’s concern that we have a high level of debt relative to many of our peers and that our debt may be continually higher than our long-term targets if we continue to make a series of acquisitions of increasingly larger size. Because of our high distribution rate, we are particularly reliant on external financing to finance our acquisitions. Moody’s indicated that our cash flows are becoming less predictable as a result of our acquisitions and expansion into the crude oil and natural gas gathering businesses. Further reductions in our credit ratings could increase the debt financing costs or possibly reduce the availability of financing. A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any indebtedness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant such a change. On January 27, 2003, Moody’s reaffirmed the Baa3 ratings on us and our subsidiary, TE Products.
Other Considerations
Credit Risks
Risks of nonpayment and nonperformance by customers are a major consideration in our businesses. Our credit procedures and policies do not fully eliminate customer credit risk. During 2002, several of our customers filed for bankruptcy protection. During the year ended December 31, 2002, we expensed approximately $0.9 million of uncollectible receivables due to customer bankruptcies and other customer nonpayments. In 2001, we expensed a receivable for transportation fees of approximately $4.3 million, or approximately $0.09 per Limited Partner and Class B Unit because of the bankruptcy of Enron Corp. and certain of its subsidiaries in December 2001.
Terrorist Threats
On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, could be a future target of terrorist organizations. These developments have subjected our operations to increased risks. Any terrorist attack on our facilities, customers’ facilities and, in some cases, those of other pipelines, could have a material adverse effect on our business. We have increased security initiatives and are working with various governmental agencies to minimize risks associated with additional terrorist attacks.
Environmental
Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.
In 1994, we entered into an Agreed Order with the IDEM that resulted in the implementation of a remediation program for groundwater contamination attributable to our operations at the Seymour terminal. In 1999, the IDEM approved a Feasibility Study, which includes our proposed remediation program. In March 2003, the IDEM issued a Record of Decision formally approving the remediation program. As the Record of Decision has been issued, we will enter into an Agreed Order for the continued operation and maintenance of the remediation program. We have an accrued liability of $0.4 million at December 31, 2002, for future remediation costs at the Seymour terminal. We do not expect that the completion of the remediation program will have a future material adverse effect on our financial position, results of operations or cash flows.
In 1994, the LDEQ issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as adjacent petroleum terminals operated by other companies. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this containment phase. At December 31, 2002, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program that we have proposed will have a future material adverse effect on our financial position, results of operations or cash flows.
At December 31, 2002, we had an accrued liability of $5.6 million and a receivable of $4.2 million from DEFS related to various TCTM sites requiring environmental remediation activities. The receivable is based on a contractual indemnity obligation we received in connection with our acquisition of assets from a DEFS affiliate in November 1998. The indemnity relates to future environmental remediation activities attributable to operations of these assets prior to our acquisition. Under this indemnity obligation, we are responsible for the first $3.0 million in specified environmental liabilities, and DEFS is responsible for those environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. The majority of the receivable from DEFS relates to remediation activities at the Velma crude oil site in Stephens County, Oklahoma. The accrued liability balance at December 31, 2002, also includes an accrual of $2.3 million related to the Shelby crude oil site in Stephens County, Oklahoma. At December 31, 2002, it is uncertain if these costs related to Shelby are covered under the indemnity obligation from DEFS. We are currently in discussions with DEFS regarding these matters. We do not expect that the completion of remediation programs associated with TCTM activities will have a future material adverse effect on our financial position, results of operations or cash flows.
Market-Based Rates
On May 11, 1999, TE Products filed an application with the FERC requesting permission to charge Market-Based Rates for substantially all refined products transportation tariffs. On July 31, 2000, the FERC issued an order granting TE Products Market-Based Rates in certain markets and set for hearing TE Products’ application for Market-Based Rates in certain destination markets and origin markets. After the matter was set for hearing, TE Products and the protesting shippers entered into a settlement agreement resolving their respective differences. On April 25, 2001, the FERC issued an order approving the offer of settlement. As a result of the settlement, TE Products recognized approximately $1.7 million of previously deferred transportation revenue in the second quarter of 2001. As a part of the settlement, TE Products withdrew the application for Market-Based Rates to the Little Rock, Arkansas, and Arcadia and Shreveport-Arcadia, Louisiana, destination markets, which are currently subject to
the PPI Index. As a result, we made refunds of approximately $1.0 million in the third quarter of 2001 for those destination markets.
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation. We will adopt SFAS 143 effective January 1, 2003. Determination of any amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.
The Downstream Segment assets consist primarily of a pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers and the distribution of lubrication oils and specialty chemicals. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from producers and transports natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionating facilities in Colorado.
The fair value of the asset retirement obligations for our trunk and interstate pipelines and our surface facilities cannot be reasonably estimated, as future dismantlement and removal dates are indeterminate. We will record such asset retirement obligations in the period in which we determine the settlement dates of the retirement obligations. Other assets in which future operating lives may be determinable include our gathering assets in our Midstream and Upstream Segments. However, our rights-of-way agreements, in general, do not require us to remove pipe or otherwise perform restoration upon taking the pipelines permanently out of service. We are continuing to evaluate the effect of SFAS 143 on our Midstream and Upstream gathering assets, but we do not currently anticipate that the adoption of SFAS 143 will have a material impact on our financial position, results of operations or cash flows.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS No. 121, Accounting for Long-Lived Assets and For Long-Lived Assets to be Disposed Of, but retains its fundamental provisions for reorganizing and measuring impairment losses on long-lived assets held for use and long-lived assets to be disposed of by sale. We adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not have a material effect on our financial position, results of operations or cash flows.
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 eliminates the requirement to classify gains and losses from the extinguishment of indebtedness as extraordinary, requires certain lease modifications to be treated the same as a sale-leaseback transaction, and makes other non-substantive technical corrections to existing pronouncements. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. We are required to adopt SFAS 145 effective January 1, 2003. We do not believe that the adoption of SFAS 145 will have a material effect on our financial position, results of operations or cash flows.
In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS 146 requires recognition of a liability for a cost associated with an exit or disposal activity
when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on our financial position, results of operations or cash flows.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not affect our financial position, results of operations or cash flows.
In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”), which addresses the disclosure to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. FIN 45 also requires the recognition of a liability by a guarantor at the inception of certain guarantees. FIN 45 requires the guarantor to recognize a liability for the non-contingent component of the guarantee, which is the obligation to stand ready to perform in the event that specified triggering events or conditions occur. The initial measurement of this liability is the fair value of the guarantee at inception. The recognition of the liability is required even it is not probable that payments will be required under the guarantee or if the guarantee was issued with a premium payment or as part of a transaction with multiple elements. We have adopted the disclosure requirements of FIN 45 (see Note 17. Commitments and Contingencies) and will apply the recognition and measurement provisions for all guarantees entered into or modified after December 31, 2002. To date, we have not entered into or modified guarantees pursuant to the provisions of FIN 45.
In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46”). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. We are required to apply FIN 46 to all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, we are required to apply FIN 46 on July 1, 2003. We do not believe FIN 46 will have a significant impact on our financial position, results of operations or cash flows.
Disclosures About Effects of Transactions with Related Parties
We have no employees and are managed by the General Partner, a wholly owned subsidiary of DEFS. Duke Energy holds an approximate 70% interest in DEFS and ConocoPhillips holds the remaining 30%. See Item 10, Directors and Executive Officers of the Registrant and Item 13, Certain Relationships and Related Transactions for discussion regarding transactions between us and DEFS, Duke Energy and ConocoPhillips.
Forward-Looking Statements
The matters discussed in this Report include “forward-looking statements” within the meaning of various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than statements of historical facts, 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 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, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses based on 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. However, 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 opportunities (or lack thereof) that may be presented to and pursued by us, competitive actions by other pipeline companies, changes in laws or regulations and other factors, many of which are beyond our control. 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.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We may be exposed to market risk through changes in commodity prices and interest rates. We do not have foreign exchange risks. Our Risk Management Committee has established policies to monitor and control these market risks. The Risk Management Committee is comprised, in part, of senior executives of the Company.
At December 31, 2002, we had $432.0 million outstanding under our variable interest rate revolving credit agreements. The interest rate is based, at our option, on either the lender’s base rate plus a spread or LIBOR plus a spread in effect at the time of the borrowings and is adjusted monthly, bimonthly, quarterly or semiannually. Utilizing the balances of variable interest rate debt outstanding at December 31, 2002, including the effects of hedging activities discussed below, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $1.8 million.
We have utilized and expect to continue to utilize interest rate swap agreements to hedge a portion of our cash flow and fair value risks. Interest rate swap agreements are used to manage the fixed and floating interest rate mix of our total debt portfolio and overall cost of borrowing. The interest rate swap related to our cash flow risk is intended to reduce our exposure to increases in the benchmark interest rates underlying our variable rate revolving credit facility. The interest rate swaps related to our fair value risks are intended to reduce our exposure to changes in the fair value of the fixed rate Senior Notes. The interest rate swap agreements involve the periodic exchange of payments without the exchange of the notional amount upon which the payments are based. The related amount payable to or receivable from counterparties is included as an adjustment to accrued interest.
At December 31, 2002, TE Products had outstanding $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). At December 31, 2002, the estimated fair value of the TE Products Senior Notes was approximately $385.8 million. At December 31, 2002, $500.0 million principal amount of the 7.625% Senior Notes due 2012 was outstanding. At December 31, 2002, the estimated fair value of the $500.0 million Senior Notes was approximately $529.1 million.
As of December 31, 2002, TE Products had an interest rate swap agreement in place to hedge its exposure to changes in the fair value of its fixed rate 7.51% TE Products Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2002, and 2001, we recognized reductions in interest expense of $8.6 million and $1.8 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the year ended December 31, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap agreement was a gain of approximately $13.6 million at December 31, 2002, and a loss of approximately $14.6 million at December 31, 2001. Utilizing the balance of the 7.51% TE Products Senior Notes outstanding at December 31, 2002, and including the effects of hedging activities, assuming market interest rates increase 100 basis points, the potential annual increase in interest expense is $2.1 million.
As of December 31, 2002, we had an interest rate swap agreement in place to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. The term of the interest rate swap matches the maturity of the credit facility. We designated this swap agreement, which hedges
exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement is based on a notional amount of $250.0 million. Under the swap agreement, we pay a fixed rate of interest of 6.955% and receive a floating rate based on a three month U.S. Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. During the years ended December 31, 2002, and 2001, we recognized increases in interest expense of $12.9 million and $6.8 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the year ended December 31, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of the interest rate swap agreement was a loss of approximately $20.1 million and $20.3 million at December 31, 2002, and 2001, respectively. We anticipate that approximately $13.5 million of the fair value will be transferred into earnings over the next twelve months.
On February 20, 2002, we entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, we terminated these interest rate swap agreements. Upon termination, the fair value of the interest rate swap agreements was $25.8 million. From inception of the swap agreements on February 20, 2002, through the termination on July 16, 2002, $7.8 million had been recognized as a reduction to interest expense. The remaining gain of approximately $18.0 million has been deferred as an adjustment to the carrying value of the Senior Notes and is being amortized using the effective interest method as a reduction to future interest expense over the remaining term of the Senior Notes. In the event of early extinguishment of the Senior Notes, any remaining unamortized gain would be recognized in the consolidated statement of income at the time of extinguishment.
Additionally, on July 16, 2002, we entered into new interest rate swap agreements to hedge our exposure to changes in the fair value of our $500.0 million principal amount of 7.625% fixed rate Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under these swap agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, which increased by approximately 50 basis points from the previous swap agreements, and received a fixed rate of interest of 7.625%. On December 12, 2002, we terminated these interest rate swap agreements. Upon termination, the fair value of the interest rate swap agreements was $33.5 million. From inception of the swap agreements on July 16, 2002, through the termination on December 12, 2002, $6.6 million had been recognized as a reduction to interest expense. The remaining gain of approximately $26.9 million has been deferred as an adjustment to the carrying value of the Senior Notes and is being amortized using the effective interest method as a reduction to future interest expense over the remaining term of the Senior Notes. In the event of early extinguishment of the Senior Notes, any remaining unamortized gain would be recognized in the consolidated statement of income at the time of extinguishment.
Item 8.
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements, together with the independent auditors’ report of KPMG LLP, begin on page of this Report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
We do not have directors or officers. We are managed by the General Partner. Officers and directors of the General Partner have management responsibilities with respect to us. Set forth below is certain information concerning the directors and executive officers of the General Partner. All directors of the General Partner are elected annually by DEFS. All officers serve at the discretion of the directors. None of the officers of the General Partner serve as officers or employees of DEFS or any other parent-affiliated company.
Jim W. Mogg, age 54, was elected a director of the General Partner in October 1997, Chairman of the Compensation Committee in April 2000 and Chairman of the Board in May 2002. Mr. Mogg succeeded William L. Thacker as Chairman of the Board in May 2002, when Mr. Thacker retired as Chairman. Prior to being elected Chairman of the Board in 2002, Mr. Mogg served as Vice Chairman of the Board from April 2000 to April 2002. Mr. Mogg is chairman, president and chief executive officer of DEFS, having been named to these positions in December 1999. Mr. Mogg also serves as Senior Vice President - Field Services of Duke Energy. Mr. Mogg was previously president of Centana Energy Corporation, a subsidiary of a predecessor of Duke Energy, from 1992 to 1999. Mr. Mogg joined Duke Energy in 1973 in the gas supply department of Panhandle Eastern Pipe Line Company.
Mark A. Borer, age 48, was elected a director of the General Partner in April 2000. Mr. Borer is executive vice president of marketing and corporate development of DEFS, having been elected in April 2002. He previously served as senior vice president, Southern Division, for DEFS, having been elected to that position in 1999 when Union Pacific Fuels, Inc. was acquired by DEFS. Before joining DEFS, he was vice president of natural gas marketing for Union Pacific Fuels, Inc. from 1992 until 1999.
Michael J. Bradley, age 48, was elected a director of the General Partner in February 2003. Mr. Bradley is executive vice president, gathering and processing of DEFS, having been elected to that position in April 2002. He previously served as senior vice president, Northern Division, for DEFS, having been elected to that position in 1999. Mr. Bradley joined DEFS in 1979 and served in a variety of positions in marketing, business development and operations.
Milton Carroll, age 52, was elected a director of the General Partner in November 1997, is a member of the Compensation, Special and Audit Committees. He served as Chairman of the Audit Committee from April 2000 until January 16, 2003. Mr. Carroll is the chairman of CenterPoint Energy, Inc., having been elected in September 2002. Mr. Carroll is the founder, and has been president and chief executive officer of Instrument Products, Inc., a manufacturer of oil field equipment and other precision products, since 1977. Mr. Carroll is a director of Ocean Energy Inc., and Chairman of the Board of Health Care Service Corporation.
Derrill Cody, age 64, was elected a director of the General Partner in 1989. He is a member of the Compensation Committee and was Chairman of the Audit Committee from April 1990 until April 2000. Mr. Cody is currently of counsel to McKinney and Stringer, P. C., which represents Duke Energy, DEFS and us in certain matters. He is also an advisor to DEFS pursuant to a personal contract. Mr. Cody served as chief executive officer of Texas Eastern Gas Pipeline Company from 1987 to 1990. Prior to that, he was executive vice president of Kerr McGee Corporation.
John P. DesBarres, age 63, was elected a director of the General Partner in May 1995. He is a member of the Compensation and Audit Committees and serves as Chairman of the Special Committee. Mr. DesBarres was formerly chairman, president and chief executive officer of Transco Energy Company from 1992 to 1995. He joined Transco in 1991 as president and chief executive officer. Prior to joining Transco, Mr. DesBarres served as chairman, president and chief executive officer for Santa Fe Pacific Pipelines, Inc. from 1988 to 1991. Mr. DesBarres is a director of American Electric Power and Penn Virginia G.P., LLC, an indirect wholly owned subsidiary of Penn Virginia Corporation, which is the general partner of Penn Virginia Resource Partners, L.P.
William W. Slaughter, age 55, was elected a director of the General Partner in April 2000. Mr. Slaughter is executive vice president of DEFS. He has been advisor to the chief executive officer of DEFS since January 1999. Mr. Slaughter was vice president of energy services for Duke Energy from 1997 until 1998, and was vice president of corporate strategic planning for PanEnergy and president of PanEnergy International Development Corporation from 1994 to 1997.
R. A. Walker, age 45, was elected director of the General Partner in July 2002, and is a member of the Compensation, Audit and Special Committees. He was elected Chairman of the Audit Committee on January 16, 2003. Mr. Walker is president, chief financial officer and director of 3TEC Energy Corporation, a publicly held independent oil and gas company. Prior to joining 3TEC Energy Corporation in 2000, Mr. Walker was senior managing director and co-head of Prudential Capital Group, an asset management firm of The Prudential Insurance Company of America from 1997 to 2000. Previously, he was managing director of Prudential Capital’s Dallas office from 1990 to 1997, where he was responsible for its worldwide energy investing.
Barry R. Pearl, age 53, was elected President of the General Partner in February 2001 and Chief Executive Officer and director in May 2002. He succeeded William L. Thacker as Chief Executive Officer in May 2002, when Mr. Thacker retired as Chief Executive Officer. Mr. Pearl was previously Chief Operating Officer from February 2001 until May 2002. Prior to joining the Company, Mr. Pearl was vice president - finance and administration, treasurer, secretary and chief financial officer of Maverick Tube Corporation from June 1998. Mr. Pearl was senior vice president and chief financial officer of Santa Fe Pacific Pipeline Partners, L.P. from 1995 until 1998, and senior vice president, business development from 1992 to 1995.
Charles H. Leonard, age 54, is Senior Vice President and Chief Financial Officer of the General Partner. Mr. Leonard joined the Company in 1988 as Vice President and Controller. In November 1989, he was elected Vice President and Chief Financial Officer. He was elected Senior Vice President in March 1990, and was Treasurer from October 1996 until May 2002.
James C. Ruth, age 55, is Senior Vice President, General Counsel and Secretary of the General Partner, having been elected in February 2001. Mr. Ruth was previously Vice President, General Counsel and Secretary from 1998 until February 2001, and Vice President, General Counsel from 1991 until 1998.
Thomas R. Harper, age 62, is Senior Vice President, Commercial Downstream of the General Partner, having been elected in February 2003. Mr. Harper was previously Vice President, Commercial Downstream from September 2000 until February 2003 and Vice President, Product Transportation and Refined Products Marketing from 1988 until September 2000. Mr. Harper joined the Company in 1987 as Director of Product Transportation.
J. Michael Cockrell, age 56, is Senior Vice President, Commercial Upstream of the General Partner, having been elected in February 2003. Mr. Cockrell was previously Vice President, Commercial Upstream from September 2000 until February 2003. He was elected Vice President of the General Partner in January 1999 and also serves as President of TEPPCO Crude GP, LLC. He joined PanEnergy in 1987 and served in a variety of positions in supply and development, including president of Duke Energy Transport and Trading Company.
Leonard W. Mallett, age 46, is Vice President, Operations of the General Partner, having been elected in September 2000. Mr. Mallett was previously Region Manager of the Southwest Region of the Company from 1994 until 1999 and Director of Engineering, from 1992 until 1994. Mr. Mallett joined the Company in 1979 as an engineer.
Stephen W. Russell, age 51, is Vice President, Support Services of the General Partner, having been elected in September 2000. Mr. Russell was previously Region Manager of the Southwest Region from July 1999 until September 2000, and Technical Operations Superintendent of the Southwest Region from 1994 until 1999. Mr. Russell joined the Company in 1988 as Project Manager in Engineering.
David E. Owen, age 53, is Vice President, Human Resources of the General Partner, having joined the Company in February 2001. He was previously Northern Division human resources manager of DEFS from May
2000 until he joined the Company. Prior to DEFS, Mr. Owen held various positions with ARCO International Oil and Gas Company from October 1996 until January 2000.
John N. Goodpasture, age 54, is Vice President, Corporate Development of the General Partner, having joined the Company in November 2001. Mr. Goodpasture was previously Vice President of Business Development for Enron Transportation Services from June 1999 until he joined the Company. Prior to his employment at Enron Transportation Services, Mr. Goodpasture spent 19 years in various executive positions at Seagull Energy Corporation (now Ocean Energy, Inc.), a large independent oil and gas company. At Seagull Energy, Mr. Goodpasture had most recently served for over ten years as Senior Vice President, Pipelines and Marketing.
Barbara A. Carroll, age 48, is Vice President, Environmental, Health and Safety, having been elected in February 2002. Ms. Carroll joined ExxonMobil in 1990 and served in a variety of management positions, including Procurement Services Manager, Materials and Service Manager and Baytown Area Public Affairs Manager until she joined the Company in February 2002. Prior to ExxonMobil, Ms. Carroll was General Manager, Corporate Environmental Protection and Compliance with Panhandle Eastern Corporation. Ms. Carroll is not related to Milton Carroll.
Mark G. Stockard, age 36, is Treasurer, having been elected in May 2002. Mr. Stockard was Assistant Treasurer of the General Partner from July 2001 until May 2002. He was previously Controller from October 1996 until May 2002. Mr. Stockard joined the Company in October 1990.
Based on information furnished to the Company and written representation that no other reports were required, to the Company’s knowledge, all applicable Section 16(a) filing requirements were complied with during the year ended December 31, 2002, except for reports covering certain transactions that were filed late by Messrs. Owen, Mallett, Ruth and Thacker.
Item 11.
Item 11. Executive Compensation
The officers of the General Partner manage and operate our business. We do not directly employ any of the persons responsible for managing or operating our operations, but instead reimburse the General Partner for the services of such persons. See Note 7 of the Notes to Consolidated Financial Statements contained elsewhere in this Report for additional information.
Directors of the General Partner who are neither officers nor employees of either the Company or DEFS receive a stipend, effective January 16, 2003, of $30,000 per annum, $1,000 for attendance at each meeting of the Board of Directors, $1,000 for attendance at each meeting of a committee of the Board of Directors and reimbursement of expenses incurred in connection with attendance at a meeting of the Board of Directors or a committee of the Board of Directors. Each non-employee director who serves as chairman of a committee of the Board of Directors receives an additional stipend of $5,000 per annum. Effective September 1, 1999, non-employee directors may elect to defer payment of retainer and attendance fees until termination of service on the Board of Directors. Such deferral may be either 50% or 100% in either a fixed income investment account that is credited with annual interest (currently 7%) or an investment account based upon the market value of Limited Partner Units.
Effective April 1, 2002, each quarter that a non-employee director continues to serve on the Board of Directors, such director will be credited with an amount equal to the then current market value of 100 Limited Partner Units and distribution equivalents on previously awarded amounts. In general, such amounts will not become distributable until the non-employee director terminates service on the Board of Directors. When a non-employee director terminates service on the Board of Directors, payment will be distributed in cash to the director according to the distribution schedule chosen by such director.
Messrs. Thacker, Mogg, Pearl, Borer, Bradley and Slaughter were not compensated for their services as directors, and it is not anticipated that any compensation for service as a director will be paid in the future to directors who are either officers or full-time employees of Duke Energy, DEFS, the General Partner or any of their affiliates.
The following table reflects cash compensation paid or accrued by the General Partner for the years ended December 31, 2002, 2001 and 2000, with respect to its Chief Executive Officer and the four most highly compensated executive officers (collectively, the “Named Executive Officers”).
SUMMARY COMPENSATION TABLE
(5)
Amounts represent the value of redemptions under the 1996 amendment to the LTICP, credits earned to Performance Unit accounts, options exercised under the terms of 1994 LTIP and payouts under the RICP.
(6)
Includes (i) Company matching contributions under funded, qualified, defined contribution retirement plans; (ii) Company matching contribution credits under unfunded, non qualified plans; and (iii) the imputed value of premiums paid by the Company for insurance on the Named Executive Officers’ lives. Amount for Mr. Pearl in 2001 also includes $74,302 of relocation expenses.
Executive Employment Contracts and Termination of Employment Arrangements
On February 12, 2001, Barry R. Pearl and the Company entered into an employment agreement, which set a minimum base salary of $220,000 per year. The Company may terminate the employment agreement for cause, death or disability. In addition, the Company or Mr. Pearl may terminate the agreement upon written notice. Mr. Pearl participates in other Company sponsored benefit plans on the same basis as other senior executives of the Company. In the event Mr. Pearl is terminated due to death or disability or by the Company for cause, Mr. Pearl is entitled only to base salary earned through the date of termination. In the event of termination for any other reason, Mr. Pearl is entitled to base salary earned through the date of termination plus a lump sum severance payment equal to two times his base annual salary and two times the current target bonus approved under the MICP by the Compensation Committee. In the event that Mr. Pearl is involuntarily terminated following a change in control, he is entitled to a lump sum severance payment equal to two times his base annual salary plus two times his current target bonus.
The Company has entered into employment agreements with certain executive officers identified in Item 10. “Directors and Executive Officers of the Registrant.” The agreements may be terminated for death, disability or by the Company with or without cause. In the event one of the named executives’ employment is terminated due to death or disability or by the Company for cause, the executive is entitled only to base salary earned through the date of termination. In the event of termination for any other reason, the executive is entitled to base salary earned through the date of termination plus a lump sum severance payment equal to two times such executive’s base annual salary and two times the current target bonus approved under the MICP by the Compensation Committee. In the event that an executive is involuntarily terminated following a change in control, the executive is entitled to a lump sum severance payment equal to two times his base annual salary plus two times his current target bonus.
Committees of the Board of Directors
Audit Committee
The Audit Committee is a standing committee of the Board of Directors of the General Partner and is comprised of three independent directors, R. A. Walker (Chairman), John DesBarres and Milton Carroll. As independent directors, the members of the Audit Committee are non-employee directors of the General Partner and are not officers, directors or otherwise affiliated with DEFS or its parent companies, ConocoPhillips or Duke Energy. The Audit Committee provides independent oversight with respect to our internal controls, accounting policies, financial reporting, internal audit function and the independent auditors. The Audit Committee also reviews the scope and quality, including the independence and objectivity of the independent and internal auditors and the fees paid for both audit and non audit work and makes recommendations on audit matters to the Board of Directors, including the engagement of the independent auditors.
Special Committee
The Special Committee is a standing committee of the Board of Directors of the General Partner and is composed of three independent directors, John DesBarres (Chairman), Milton Carroll and R. A. Walker. The members of the Special Committee are non-employee directors of the General Partner and are not officers, directors or otherwise affiliated with DEFS or its parent companies, ConocoPhillips or Duke Energy. The Special Committee is responsible for the independent evaluation of the fairness and reasonableness of affiliate transactions and the approval or rejection of those transactions that would ordinarily require Board approval involving the General
Partner, DEFS or an affiliate of either, and us. Such transactions include related party asset sales and operating agreements. The Special Committee is also responsible for the evaluation of the fairness and approval or rejection of the issuance and pricing of additional Limited Partner Units and debt.
Compensation Committee Interlocks and Insider Participation
During 2002, Jim W. Mogg, a director of the General Partner and chairman, president and chief executive officer of DEFS, was chairman of the Compensation Committee of the General Partner and participated in deliberations concerning the General Partner’s executive officer compensation. The other four members of the Compensation Committee of the General Partner, Milton Carroll, R. A. Walker, Derrill Cody and John P. DesBarres, are non-employee directors of the General Partner and are not officers or directors of DEFS or its parent companies, ConocoPhillips or Duke Energy. In July 2002, Mr. Walker replaced Carl D. Clay as a member of the Compensation Committee, upon Mr. Clay’s retirement from the Board of Directors.
Compensation Pursuant to General Partner Plans
Management Incentive Compensation Plan
The General Partner has established the MICP, which provides for the payment of additional cash compensation to participants if certain Partnership performance objectives and personal objectives are met each year. The Compensation Committee of the Board of Directors of the General Partner (the “Committee”) determines at the beginning of each year which employees are eligible to become participants in the MICP. Additional participants may be added to the plan during the year by the Chief Executive Officer. Each participant is assigned a target award, determined as a percentage of total annual salary for the plan year less any incentive compensation payments during the plan year, by the Committee. Such target award determines the additional compensation to be paid if certain performance objectives and personal objectives are met. The amount of the target awards may range from 10% to 55% of a participant’s base salary. Maximum payout under the MICP is 144% of a participant’s target award. Awards are paid as soon as practicable following approval by the Committee after the close of a year.
1994 Long Term Incentive Plan
The 1994 LTIP authorized incentive awards to key employees whereby a participant was granted an option to purchase Units together with a stipulated number of Performance Units, which provided for cash credits to participants’ accounts when annual earnings exceeded specified levels. No awards have been made under the 1994 LTIP since 1999, and none are expected to be made in the future.
The following table provides information concerning the Unit options exercised under the 1994 LTIP by each of the Named Executive Officers during 2002 and the value of unexercised Unit options under the 1994 LTIP to the Named Executive Officers as of December 31, 2002. The value assigned to each unexercised, “in the money” option is based on the positive spread between the exercise price of such option and the fair market value of a Limited Partner Unit on December 31, 2002. The fair market value is the average of the high and low prices of a Limited Partner Unit as reported in The New York Times on the last business day in 2002. In assessing the value, it should be kept in mind that no matter what theoretical value is placed on an option on a particular date, its ultimate value will be dependent on the market value of our Limited Partner Unit price at a future date. The future value will depend in part on the efforts of the Named Executive Officers to foster our future success for the benefit of all unitholders.
AGGREGATED OPTIONS EXERCISES IN YEAR ENDED DECEMBER 31, 2002 AND
OPTION VALUES AT DECEMBER 31, 2002
2000 Long Term Incentive Plan
Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom Limited Partner Units granted under the award multiplied by (3) the average of the closing prices of a Limited Partner Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added (as defined below) during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period.
The performance period applicable to awards granted in 2002 is the three-year period that commenced on January 1, 2002, and ends on December 31, 2004. Each participant’s performance percentage is the result of [(A) minus (B)] divided by [(C) minus (B)] where (A) is the actual Economic Value Added for the performance period, (B) is $59.9 million (which represents the actual Economic Value Added for the three-year period immediately preceding the performance period) and (C) is $71.7 million (which represents the Target Economic Value Added during the three-year performance period). No amounts will be payable under the awards granted in 2002 for the
2000 LTIP unless Economic Value Added for the three year performance period exceeds $59.9 million. The performance percentage may not exceed 150%.
Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that in its discretion the Compensation Committee of the General Partner may exclude gains or losses from extraordinary, unusual or non-recurring items. Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment, plus products and crude oil linefill and the gross value of intangibles and equity investments. Our cost of capital is approved by the Committee at the date of award grant.
In addition to the payment described above, during the performance period, the General Partner will pay to the Participant the amount of cash distributions that we would have paid to our Unitholders had the participant been the owner of the number of Limited Partner Units equal to the number of phantom Limited Partner Units granted to the participant under this award.
The following table provides information concerning awards under the 2000 LTIP to each of the Named Executive Officers during 2002.
(1)
Phantom units will be settled in cash based upon the then market price of the Units at the end of the performance period as described above.
(2)
No amounts will be payable for awards granted in 2002 unless Economic Value Added for the three year performance period exceeds $59.9 million.
(3)
In number of phantom units. Pursuant to Instruction 5 to Regulation 402(e) of the Securities and Exchange Commission, these amounts assume that the 44% increase in Economic Value Added for 2002 as compared with 2001 is maintained for each of the three years in the performance period. There can be no assurance that any specific amount of Economic Value Added will be attained for such period.
(4)
The maximum potential payout under the 2000 LTIP is 150% of phantom units awarded.
Pension Plan
Prior to the transfer of the General Partner interest from Duke Energy to DEFS on April 1, 2000, the Company’s employees participated in the Duke Energy Retirement Cash Balance Plan, which is a noncontributory, trustee-administered pension plan. Effective January 1, 1999, the benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age, and service. In addition, the Named Executive Officers participated in the Duke Energy Executive Cash Balance Plan, which is a noncontributory, nonqualified, defined benefit retirement plan. The Duke Energy Executive Cash Balance Plan was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans.
Benefits under the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance Plan were based on eligible pay, generally consisting of base pay, short term incentive pay, and lump-sum merit increases. The Duke Energy Retirement Cash Balance Plan excludes deferred compensation, other than deferrals pursuant to Sections 401(k) and 125 of the Internal Revenue Code. As part of the change in ownership on March 31, 2000, the Company is no longer responsible for the funding of the liabilities associated with the Duke Energy Retirement Cash Balance Plan or the Duke Energy Executive Cash Balance Plan.
Effective April 1, 2000, the Company adopted the TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) and the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”). The benefits and provisions of these plans are substantially identical to the Duke Energy Retirement Cash Balance Plan and the Duke Energy Executive Cash Balance Plan previously in effect prior to April 1, 2000.
Under the cash balance benefit accrual formula that applies in determining benefits under the TEPPCO RCBP, an eligible employee’s plan account receives a pay credit at the end of each month in which the employee remains eligible and receives eligible pay for services. The monthly pay credit is equal to a percentage of the employee’s monthly eligible pay. The percentage depends on age added to completed years of services at the beginning of the year, as shown below:
The above monthly pay credit is increased by an additional 4% of any portion of eligible pay above the Social Security taxable wage base ($84,900 for 2002). Employee accounts also receive monthly interest credits on their balances. The rate of the interest credit is adjusted quarterly and is derived from the average annual yield on 30-year U.S. Treasury Bonds during the third week of the last month of the previous quarter, subject to a minimum rate of 4% per year and a maximum rate of 9% per year.
Assuming that the Named Executive Officers continue in their present positions at their present salaries until retirement at age 65, their estimated annual pensions in a single life annuity form under the applicable pension plan(s) (including the Duke Energy Retirement Cash Balance Plan, the Duke Energy Executive Cash Balance Plan, the TEPPCO RCBP and the TEPPCO SBP) attributable to such salaries would be as follows: Barry R. Pearl, $63,658; J. Michael Cockrell, $43,721; Charles H. Leonard, $98,340; James C. Ruth, $166,111; and John N. Goodpasture, $33,270. Such estimates were calculated assuming interest credits at a rate of 6% per annum and using a future Social Security taxable wage base equal to $87,000.
In 2002, William L. Thacker commenced benefit payments in the Duke Energy Retirement Cash Balance Plan, the TEPPCO RCBP and the Duke Energy Executive Cash Balance Plan. Under the Duke Energy Retirement Cash Balance Plan and the TEPPCO RCBP, Mr. Thacker elected to receive his benefits as a one time payment. The amounts paid from the Duke Energy Retirement Cash Balance Plan and the TEPPCO RCBP were $136,964 and $45,508, respectively. Mr. Thacker’s benefits under the Duke Energy Executive Cash Balance Plan will be paid out over 10 years. On January 1, 2003, the remaining balance to be paid out under the Duke Energy Executive Cash Balance Plan was $265,052. In February 2003, Mr. Thacker received his benefit under the TEPPCO SBP in the form of a one time payment of $191,670.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Equity Compensation Plan Information
The following table provides information about our Equity Compensation Plans. See Note 14. Unit-Based Compensation for a description of the compensation plans.
Security Ownership of Certain Beneficial Owners
As of March 7, 2003, Duke Energy, through its ownership of the Company and other subsidiaries, owns 2,500,000 Limited Partner Units, representing 4.6% of the Limited Partner Units outstanding; and 3,916,547 Class B Units, representing 100% of the Class B Units, or 11.1% of the two classes of Units combined. The following table sets forth information of each person other than Duke Energy known to us to be the beneficial owner of more than 5% of our voting shares as of March 14, 2003:
(1)
Goldman, Sachs & Co. reported shared voting and dispositive power in its most recent report on Schedule 13G/A filed February 11, 2003. Goldman, Sachs & Co. is registered investment adviser whose clients have the right to receive distributions from, and the proceeds from the sale of, such shares.
No other person is known by us to own more than 5% of our outstanding Units.
Security Ownership of Management
The following table sets forth certain information, as of March 14, 2003, concerning the beneficial ownership of Limited Partner Units by each director and Named Executive Officer of the General Partner and by all directors and officers of the General Partner as a group. Such information is based on data furnished by the persons named. Based on information furnished to the General Partner by such persons, no director or officer of the General Partner owned beneficially, as of March 14, 2003, more than 1% of the 53.8 million Limited Partner Units outstanding at that date.
(1)
Unless otherwise indicated, the persons named above have sole voting and investment power over the Units reported. Includes Units that the named person has the right to acquire within 60 days.
(2)
Includes 2,227 Units owned by daughters.
Item 13.
Item 13. Certain Relationships and Related Transactions
Our Management
We have no employees and are managed by the Company, a wholly owned subsidiary of DEFS. Duke Energy holds an approximate 70% interest in DEFS and ConocoPhillips holds the remaining 30%. According to the Partnership Agreements, the Company is entitled to reimbursement of all direct and indirect expenses related to our business activities.
For the years ended December 31, 2002, 2001, and 2000, direct expenses incurred by the Company of $69.6 million, $68.2 million and $50.4 million, respectively, were charged to us by DEFS. Substantially all such costs were related to payroll and payroll related expenses. For the years ended December 31, 2002, 2001, and 2000, expenses for administrative services and overhead allocated to us by Duke Energy and its affiliates were $0.8 million, $0.6 million, and $0.8 million, respectively.
Transactions with DEFS
Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $7.4 million, $7.4 million and $7.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS. Expenses related to the Operation and Maintenance Agreement totaled $0.9 million, $0.9 million, $0.9 million for the years ended December 31, 2002, 2001 and 2000, respectively.
Included with crude oil assets purchased from DEFS effective November 1, 1998, was the Wilcox NGL Pipeline located along the Texas Gulf Coast. The Wilcox NGL Pipeline transports NGLs for DEFS from two of their processing plants and is currently supported by a throughput agreement with DEFS through 2005. The fees paid to us by DEFS under the agreement totaled $1.2 million, $1.2 million and $1.1 million for the years ended December 31, 2002, 2001 and 2000, respectively. The Panola Pipeline and San Jacinto Pipeline were purchased on December 31, 2000, from DEFS for $91.7 million. These pipelines originate at DEFS’ East Texas Plant Complex in Panola County, Texas. For the years ended December 31, 2002 and 2001, revenues recognized included $12.0 million and $13.9 million, respectively, from a subsidiary of DEFS for NGL transportation fees on the Panola and San Jacinto Pipelines.
Effective May 2001, we entered into an agreement with DEFS to commit sole utilization of our Providence terminal to DEFS. We operate the terminal and provide propane loading services to DEFS. During the years ended December 31, 2002 and 2001, revenues of $2.3 million and $1.5 million from DEFS, respectively, were recognized pursuant to this agreement.
On September 30, 2001, we completed the acquisition of Jonah. The Jonah assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the years ended December 31, 2002 and 2001, we recognized $3.3 million and $0.6 million, respectively, of expense related to the management of the Jonah assets by DEFS.
On March 1, 2002, we completed the acquisition of the Chaparral NGL system. The Chaparral assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the year ended December 31, 2002, we recognized $1.7 million of expenses related to the management of the Chaparral assets by DEFS.
On June 30, 2002, we completed the acquisition of Val Verde. The Val Verde assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the year ended December 31, 2002, we recognized $1.2 million of expenses related to the management of the Val Verde assets by DEFS.
Interest of the General Partner in the Partnership
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 sole discretion. According to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds as follows:
During the year ended December 31, 2002, distributions paid to the General Partner totaled $37.7 million, including incentive distributions of $35.4 million.
Interests of Duke Energy in the Partnership
In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to Limited Partner Units and are treated as Limited Partner Units for purposes of this Report. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. Pursuant to our Partnership Agreement, we have registered the resale by Duke Energy of such Limited Partner Units with the Securities and Exchange Commission. As of December 31, 2002, no such Limited Partner Units had been sold by Duke Energy.
At December 31, 2002, Duke Energy also held 3,916,547 Class B Units. All of the Class B Units were issued to Duke Energy in connection with an acquisition of assets initially acquired in the Upstream Segment in 1998. The Class B Units share in income and distributions on the same basis as the Limited Partner Units, but they are not listed on the New York Stock Exchange. The Class B Units may be converted into Limited Partner Units upon approval by the unitholders. We have the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if the conversion is denied, Duke Energy, as holder of the Class B Units, will have the right to sell them to us at 95.5% of the 20-day average market closing price of the Limited Partner Units, as determined under our Partnership Agreement.
Item 14.
Item 14. Controls and Procedures
Included in its recent Release No. 34-46427, effective August 29, 2002, the Securities and Exchange Commission adopted rules requiring reporting companies to maintain disclosure controls and procedures to provide reasonable assurance that a registrant is able to record, process, summarize and report the information required in the registrant’s quarterly and annual reports under the Securities Exchange Act of 1934 (the “Exchange Act”). While we believe that our existing disclosure controls and procedures have been effective to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to monitor ongoing developments in this area.
The principal executive officer and principal financial officer of our general partner, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-14(c) and Rule 15d-14(c)) as of a date within 90 days before the filing date of this Report, have concluded that, as of such date, our disclosure controls and procedures are adequate and effective to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities.
There have been no changes in our internal controls or in other factors known to us that could significantly affect those internal controls subsequent to the date of the evaluation, nor were there any significant deficiencies or material weaknesses in our internal controls. As a result, no corrective actions were required or undertaken.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents are filed as a part of this Report:
(1)
Financial Statements: See Index to Financial Statements and Supplemental Schedule on page of this Report for financial statements filed as part of this Report.
(2)
Financial Statement Schedules: See Index to Financial Statements and Supplemental Schedule on page of this Report for financial statement schedules filed as part of this Report.
(3)
Exhibits.
* Filed herewith.
+ A management contract or compensation plan or arrangement.
(b)
Reports on Form 8-K filed during the quarter ended December 31, 2002:
Reports on Form 8-K were filed on October 8, 2002, October 9, 2002, October 21, 2002 and November 12, 2002.
SIGNATURES
TEPPCO Partners, L.P., pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
TEPPCO Partners, L.P.
(Registrant)
(A Delaware Limited Partnership)
By: Texas Eastern Products Pipeline
Company, LLC, as General Partner
By: /s/ BARRY R. PEARL
Barry R. Pearl,
President and Chief Executive Officer
By: /s/ CHARLES H. LEONARD
Charles H. Leonard,
Senior Vice President and Chief Financial Officer
Dated: March 21, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
* Signed on behalf of the Registrant and each of these persons:
By: /s/ CHARLES H. LEONARD
(Charles H. Leonard, Attorney-in-Fact)
CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, BARRY R. PEARL, certify that:
1.
I have reviewed this annual report on Form 10-K of TEPPCO Partners, L.P.;
2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b)
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6.
The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
March 21, 2003
Date
/s/ BARRY R. PEARL
Barry R. Pearl
Senior President and Chief Executive Officer
CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE
SARBANES-OXLEY ACT OF 2002
I, CHARLES H. LEONARD, certify that:
1.
I have reviewed this annual report on Form 10-K of TEPPCO Partners, L.P.;
2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b)
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
6.
The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
March 21, 2003
Date
/s/ CHARLES H. LEONARD
Charles H. Leonard
Senior Vice President and Chief Financial Officer
CONSOLIDATED FINANCIAL STATEMENTS
OF TEPPCO PARTNERS, L.P.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULE
INDEPENDENT AUDITORS’ REPORT
To the Partners of
TEPPCO Partners, L.P.:
We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2002 and 2001, and the related consolidated statements of income, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.
As described in Note 2 to the consolidated financial statements, as of January 1, 2001, the Partnership changed its method of accounting for derivative instruments and hedging activities and, effective January 1, 2002, adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
KPMG LLP
Houston, Texas
January 22, 2003, except as
to Note 22, which is as of
February 10, 2003
TEPPCO PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(in thousands)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per Unit amounts)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands, except Unit amounts)
See accompanying Notes to Consolidated Financial Statements.
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. PARTNERSHIP ORGANIZATION
TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us. The General Partner is a wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Duke Energy holds an approximate 70% interest in DEFS, and ConocoPhillips holds the remaining 30%. The Company, as general partner, performs all management and operating functions required for us, except for the management and operations of certain of the TEPPCO Midstream assets that are managed by DEFS on our behalf. We reimburse the General Partner for all reasonable direct and indirect expenses incurred in managing us.
As used in this Report, “we,” “us,” “our,” and the “Partnership” means TEPPCO Partners, L.P. and, where the context requires, includes our subsidiaries.
On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly owned by us. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us. In exchange for this contribution, the Company’s interest as our general partner was increased to 2%. The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in us and the Operating Partnerships. As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt.
At formation in 1990, we completed an initial public offering of 26,500,000 Units representing Limited Partner Interests (“Limited Partner Units”) at $10.00 per Unit. In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs began participating in distributions of cash and allocations of profit and loss in a manner identical to Limited Partner Units and are treated as Limited Partner Units for purposes of this Report. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. Pursuant to our Partnership Agreement, we have registered the resale by Duke Energy of such Limited Partner Units with the Securities and Exchange Commission. As of December 31, 2002, no such Limited Partner Units had been sold by Duke Energy.
At December 31, 2002 and 2001, we had outstanding 53,809,597 and 40,450,000 Limited Partner Units and 3,916,547 and 3,916,547 Class B Limited Partner Units (“Class B Units”), respectively. All of the Class B Units were issued to Duke Energy in connection with an acquisition of assets initially acquired in the Upstream Segment in 1998. The Class B Units share in income and distributions on the same basis as the Limited Partner Units, but they are not listed on the New York Stock Exchange. The Class B Units may be converted into Limited Partner Units upon approval by the unitholders. We have the option to seek approval for the conversion of the Class B Units into Limited Partner Units; however, if the conversion is denied, Duke Energy, as holder of the Class B Units, will have the right to sell them to us at 95.5% of the 20-day average market closing price of the Limited Partner Units, as determined under our Partnership Agreement. As a result of this option, we have not included the Class B Units in partners’ capital at December 31, 2002 and 2001. Collectively, the Limited Partner Units and Class B Units are referred to as “Units.”
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NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We follow the following significant accounting policies in the preparation of our consolidated financial statements.
Basis of Presentation and Principles of Consolidation
The financial statements include our accounts on a consolidated basis. The Company’s 1% general partner interest in the Operating Partnerships, prior to July 26, 2001, is accounted for as a minority interest. We have eliminated all significant intercompany items in consolidation. We have reclassified certain amounts from prior periods to conform with the current presentation.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
Environmental Expenditures
We accrue for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs, including direct internal and legal costs, is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations.
Business Segments
We operate and report in three business segments: transportation and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”); gathering, transportation, marketing and storage of crude oil; and distribution of lubrication oils and specialty chemicals (“Upstream Segment”); and gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and transportation of NGLs (“Midstream Segment”). Our reportable segments offer different products and services and are managed separately because each requires different business strategies.
Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which was previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL
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pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation.
Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). Refined products, LPGs, petrochemicals, crude oil, NGLs and natural gas are referred to in this Report, collectively, as “petroleum products” or “products.”
Revenue Recognition
Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, storage and short-haul transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold.
Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals principally in Oklahoma, Texas and the Rocky Mountain region. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas (effective July 20, 2000). Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product
by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, L.P., which typically occurs upon our receipt of the product. Revenues related to trade documentation and pumpover fees are recognized as services are completed.
Except for crude oil purchased from time to time as inventory, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged.
Our Midstream Segment revenues are derived from the gathering of natural gas, fractionation of NGLs and transportation of NGLs. Gathering and transportation revenues are recognized as natural gas or NGLs are delivered to customers. Revenues are also earned from the sale of condensate liquid extracted from the natural gas stream to an Upstream marketing affiliate. Fractionation revenues are recognized ratably over the contract year as products are delivered to DEFS. We do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.
Natural Gas Imbalances
Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated. Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead. If the customers supply more natural gas gathering volumes than they nominated, the Val Verde Gathering System (“Val Verde”) and the Jonah Gas Gathering System (“Jonah”) record a payable for the amount due to customers and also record a receivable for the same amount due from connecting pipeline transporters or shippers. If the customers supply less natural gas gathering volumes than
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they nominated, the Val Verde and the Jonah systems record a receivable reflecting the amount due from customers and a payable for the same amount due to connecting pipeline transporters or shippers.
Quantities of natural gas over or under delivered related to imbalance agreements are recorded monthly using then current index prices. These imbalances are settled with cash or deliveries of natural gas. Gains are recorded when gas volumes owed (receivables) are settled by gas producers at a later date during a period of increasing prices, or if Val Verde and Jonah settle payables at later date during a period of falling prices. Losses are recorded if these processes are reversed.
Use of Derivatives
We account for derivative financial instruments in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Special accounting for derivatives qualifying as fair value hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of income. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings.
We have utilized and expect to continue to utilize interest rate swap agreements to hedge a portion of our cash flow and fair value risks. Interest rate swap agreements are used to manage the fixed and floating interest rate mix of our total debt portfolio and overall cost of borrowing. The interest rate swap related to our cash flow risk is intended to reduce our exposure to increases in the benchmark interest rates underlying our variable rate revolving credit facility. The interest rate swaps related to our fair value risks are intended to reduce our exposure to changes in the fair value of our fixed rate Senior Notes. The interest rate swap agreements involve the periodic exchange of payments without the exchange of the notional amount upon which the payments are based. The related amount payable to or receivable from counterparties is included as an adjustment to accrued interest.
By using interest rate swap agreements to hedge exposures to changes in interest rates and the fair value of fixed rate Senior Notes, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk for us. When the fair value of a derivative contract is negative, we owe the counterparty and, therefore, we do not possess credit risk. We minimize the credit risk in derivative instruments by entering into transactions with major financial institutions. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We manage market risk associated with interest rate contracts by establishing and monitoring parameters that limit the type and degree of market risk that may be undertaken.
We adopted SFAS 133 at January 1, 2001, which resulted in the recognition of approximately $10.1 million of derivative liabilities, $4.1 million of which were current liabilities and $6.0 million of which were noncurrent liabilities, and $10.1 million of hedging losses included in accumulated other comprehensive income, a component of partners’ capital, as the cumulative effect of the change in accounting. The hedging losses included in accumulated other comprehensive loss are transferred to earnings as the forecasted transactions actually occur. Amounts determined as of January 1, 2001, were based on the market quote of our interest swap agreement in place at the time of adoption.
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Inventories
Inventories consist primarily of petroleum products and crude oil which are valued at the lower of cost (weighted average cost method) or market. Our Downstream Segment acquires and disposes of various products under exchange agreements. Receivables and payables arising from these transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories.
Property, Plant and Equipment
We record property, plant and equipment at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).
We evaluate impairment of long-lived assets in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of, and effective January 1, 2002, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.
Capitalization of Interest
We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 5.11%, 6.46% and 7.45% for the years ended December 31, 2002, 2001 and 2000, respectively. During the years ended December 31, 2002, 2001 and 2000, the amount of interest capitalized was $4.3 million, $4.0 million and $4.6 million, respectively.
Intangible Assets
Intangible assets at December 31, 2002, consist primarily of production contracts assumed in the acquisition of Jonah on September 30, 2001, and the acquisition of Val Verde on June 30, 2002, and the fractionation agreement with DEFS.
In connection with the acquisitions of Jonah and Val Verde, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming, and we assumed fixed-term contracts with customers that transport coal bed methane (“CBM”) from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, respectively (see Note 5. Acquisitions). The value assigned to intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production. The value assigned to intangible assets is amortized on a unit of production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. The amortization of the Jonah and Val Verde systems are expected to average approximately 16 years and 20 years, respectively. On a quarterly basis, we update production estimates of the natural gas wells and evaluate the remaining expected useful life of the contract
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
assets. At December 31, 2002, the unamortized balance of the Jonah and Val Verde production contracts were $205.2 million and $228.6 million, respectively.
In connection with the purchase of the fractionation facilities in 1998, we entered into a fractionation agreement with DEFS. The fractionation agreement is being amortized over a period of 20 years, which is the term of the agreement with DEFS. At December 31, 2002, the unamortized balance of this agreement was $29.0 million (see Note 7. Related Party Transactions.)
Goodwill
Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets which was issued by the Financial Accounting Standards Board (“FASB”) in July 2001 (see Note 3. Goodwill and Other Intangible Assets). SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives. Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill or amortization expense related to the excess investment on our equity investment (equity method goodwill).
Income Taxes
We are a limited partnership. As such, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statements of income, is includable in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal income taxes for our operations. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each unitholders’ tax attributes in the Partnership.
Cash Flows
For purposes of reporting cash flows, all liquid investments with maturities at date of purchase of 90-days or less are considered cash equivalents.
Net Income Per Unit
Basic net income per Unit is computed by dividing net income, after deduction of the General Partner’s interest, by the weighted average number of Limited Partner and Class B Units outstanding (a total of 49.2 million Units, 39.3 million Units and 33.6 million Units for the years ended December 31, 2002, 2001 and 2000, respectively). The General Partner’s percentage interest in net income is based on its percentage of cash distributions from Available Cash for each year (see Note 13. Quarterly Distributions of Available Cash). The General Partner was allocated $29.7 million (representing 25.18%) of net income for the year ended December 31, 2002, $23.5 million (representing 21.54%) of net income for the year ended December 31, 2001, and $13.9 million (representing 17.96%) of net income for the year ended December 31, 2000. The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increases.
Diluted net income per Unit is similar to the computation of basic net income per Unit above, except that the denominator was increased to include the dilutive effect of outstanding Unit options by application of the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
treasury stock method. For the years ended December 31, 2002, 2001 and 2000, the denominator was increased by 32,053 Units, 41,864 Units and 20,926 Units, respectively.
Unit Option Plan
We have not granted options for any periods presented. For options outstanding under the 1994 Long Term Incentive Plan (see Note 14. Unit-Based Compensation), we followed the intrinsic value method of accounting for recognizing stock-based compensation expense. Under this method, we record no compensation expense for unit options granted when the exercise price of the options granted is equal to, or greater than, the market price of our Limited Partner Units on the date of the grant.
In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure was issued. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, and provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002, and are included in Note 14. Unit-Based Compensation.
The following table summarizes pro forma net income and net income per Unit for the years ended December 31, 2002, 2001 and 2000 assuming we had used the fair value method of accounting for our unit option plan (in thousands, except per Unit amounts):
For purposes of determining compensation costs using the provisions of SFAS 123, the fair value of option grants was determined using the Black-Scholes option-valuation model. The key input variables used in valuing the options were as follows: average risk-free interest rate based on five- and 10-year Treasury bonds - 4.7%; Unit price volatility - 23%; dividend yield - 7.6%; and estimated option lives - six years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
New Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation. We will adopt SFAS 143 effective January 1, 2003. Determination of any amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.
The Downstream Segment assets consist primarily of a pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from producers and transports natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionating facilities in Colorado.
The fair value of the asset retirement obligations for our trunk and interstate pipelines and our surface facilities cannot be reasonably estimated, as future dismantlement and removal dates are indeterminate. We will record such asset retirement obligations in the period in which we determine the settlement dates of the retirement obligations. Other assets in which future operating lives may be determinable include our gathering assets in our Midstream and Upstream Segments. However, our rights-of-way agreements, in general, do not require us to remove pipe or otherwise perform restoration upon taking the pipelines permanently out of service. We are continuing to evaluate the effect of SFAS 143 on our Midstream and Upstream gathering assets, but we do not currently anticipate that the adoption of SFAS 143 will have a material impact on our financial position, results of operations or cash flows.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 supercedes SFAS No. 121, Accounting for Long-Lived Assets and For Long-Lived Assets to be Disposed Of, but retains its fundamental provisions for reorganizing and measuring impairment losses on long-lived assets held for use and long-lived assets to be disposed of by sale. We adopted SFAS 144 effective January 1, 2002. The adoption of SFAS 144 did not have a material effect on our financial position, results of operations or cash flows.
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS 145 eliminates the requirement to classify gains and losses from the extinguishment of indebtedness as extraordinary, requires certain lease modifications to be treated the same as a sale-leaseback transaction, and makes other non-substantive technical corrections to existing pronouncements. SFAS 145 is effective for fiscal years beginning after May 15, 2002, with earlier adoption encouraged. We are required to adopt SFAS 145 effective January 1, 2003. We do not believe that the adoption of SFAS 145 will have a material effect on our financial position, results of operations or cash flows.
In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS 146 requires recognition of a liability for a cost associated with an exit or disposal activity
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when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on our financial position, results of operations or cash flows.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not affect our financial position, results of operations or cash flows.
In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”), which addresses the disclosure to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. FIN 45 also requires the recognition of a liability by a guarantor at the inception of certain guarantees. FIN 45 requires the guarantor to recognize a liability for the non-contingent component of the guarantee, which is the obligation to stand ready to perform in the event that specified triggering events or conditions occur. The initial measurement of this liability is the fair value of the guarantee at inception. The recognition of the liability is required even it is not probable that payments will be required under the guarantee or if the guarantee was issued with a premium payment or as part of a transaction with multiple elements. We have adopted the disclosure requirements of FIN 45 (see Note 17. Commitments and Contingencies) and will apply the recognition and measurement provisions for all guarantees entered into or modified after December 31, 2002. To date, we have not entered into or modified guarantees pursuant to the provisions of FIN 45.
In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46”). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. We are required to apply FIN 46 to all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, we are required to apply FIN 46 on July 1, 2003. We do not believe FIN 46 will have a significant impact on our financial position, results of operations or cash flows.
NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS
In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets. SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives.
Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill or amortization expense related to the excess investment on our equity investment in Seaway Crude Pipeline Company (see Note 6. Equity Investments). The following table presents our results on a comparable basis, as if we had not recorded amortization expense of goodwill or amortization expense of our excess investment in Seaway Crude Pipeline Company for the years ended December 31, 2002, 2001 and 2000 (in thousands, except per Unit amounts):
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Upon the adoption of SFAS 142, we were required to reassess the useful lives and residual values of all intangible assets acquired, and make necessary amortization period adjustments by the end of the first interim period after adoption. We completed this analysis during the year ended December 31, 2002, resulting in no change to the amortization period for our intangible assets. We will continue to reassess the useful lives and residual values of all intangible assets on an annual basis.
In connection with the transitional goodwill impairment evaluation required by SFAS 142, we were required to perform an assessment of whether there was an indication that goodwill was impaired as of the date of adoption. We accomplished this by identifying our reporting units and determining the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units as of the date of adoption. We then determined the fair value of each reporting unit and compared it to the carrying value of the reporting unit. We completed this analysis during the second quarter of 2002, resulting in no transitional impairment loss. We will continue to compare the fair value of each reporting unit to the carrying value on an annual basis to determine if an impairment loss has occurred.
At December 31, 2002, we had $16.9 million of unamortized goodwill and $25.5 million of excess investment in our equity investment (equity method goodwill). We completed an impairment analysis of the excess investment in our equity investment during the year ended December 31, 2002, and we noted no indication of impairment. The excess investment is included in our equity investments account at December 31, 2002. The following table presents the carrying amount of goodwill and excess investment at December 31, 2002, by business segment (in thousands):
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The following table reflects the components of amortized intangible assets, excluding goodwill (in thousands):
Excluding goodwill, amortization expense on intangible assets was $27.9 million, $5.5 million and $2.0 million for the years ended December 31, 2002, 2001 and 2000, respectively.
The following table sets forth the estimated amortization expense on intangible assets for the years ending December 31 (in thousands):
NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS
We have entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. The term of the interest rate swap matches the maturity of the credit facility. We designated this swap agreement, which hedges exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement is based on a notional amount of $250.0 million. Under the swap agreement, we pay a fixed rate of interest of 6.955% and receive a floating rate based on a three month U.S. Dollar LIBOR rate. Since this swap is designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. During the years ended December 31, 2002, and 2001, we recognized increases in interest expense of $12.9 million and $6.8 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the year ended December 31, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of the interest rate swap agreement was a loss of approximately $20.1 million and $20.3 million at December 31, 2002, and 2001, respectively. We anticipate that approximately $13.5 million of the fair value will be transferred into earnings over the next twelve months.
On October 4, 2001, our TE Products subsidiary entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate based on a three month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2002, and 2001, we recognized reductions in interest expense of $8.6 million and $1.8 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the year ended December 31, 2002, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be
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recognized. The fair value of this interest rate swap agreement was a gain of approximately $13.6 million at December 31, 2002, and a loss of approximately $14.6 million at December 31, 2001.
On February 20, 2002, we entered into interest rate swap agreements to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. On July 16, 2002, we terminated these interest rate swap agreements. Upon termination, the fair value of the interest rate swap agreements was $25.8 million. From inception of the swap agreements on February 20, 2002, through the termination on July 16, 2002, $7.8 million had been recognized as a reduction to interest expense. The remaining gain of approximately $18.0 million has been deferred as an adjustment to the carrying value of the Senior Notes and is being amortized using the effective interest method as a reduction to future interest expense over the remaining term of the Senior Notes. In the event of early extinguishment of the Senior Notes, any remaining unamortized gain would be recognized in the consolidated statement of income at the time of extinguishment.
Additionally, on July 16, 2002, we entered into new interest rate swap agreements to hedge our exposure to changes in the fair value of our $500.0 million principal amount of 7.625% fixed rate Senior Notes due 2012. We designated these swap agreements as fair value hedges. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under these swap agreements, we paid a floating rate based on a six month U.S. Dollar LIBOR rate, plus a spread, which increased by approximately 50 basis points from the previous swap agreements, and received a fixed rate of interest of 7.625%. On December 12, 2002, we terminated these interest rate swap agreements. Upon termination, the fair value of the interest rate swap agreements was $33.5 million. From inception of the swap agreements on July 16, 2002, through the termination on December 12, 2002, $6.6 million had been recognized as a reduction to interest expense. The remaining gain of approximately $26.9 million has been deferred as an adjustment to the carrying value of the Senior Notes and is being amortized using the effective interest method as a reduction to future interest expense over the remaining term of the Senior Notes. In the event of early extinguishment of the Senior Notes, any remaining unamortized gain would be recognized in the consolidated statement of income at the time of extinguishment.
NOTE 5. ACQUISITIONS
On July 20, 2000, we completed an acquisition of ARCO Pipe Line Company (“ARCO”), a wholly owned subsidiary of Atlantic Richfield Company, for $322.6 million, which included $4.1 million of acquisition related costs other than the purchase price. The purchased assets included ARCO’s 50% ownership interest in Seaway Crude Pipeline Company (“Seaway”), which owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston areas. We assumed ARCO’s role as operator of this pipeline. We also acquired: (i) ARCO’s crude oil terminal facilities in Cushing and Midland, Texas, including the line transfer and pumpover business at each location; (ii) an undivided ownership interest in both the Rancho Pipeline, a crude oil pipeline from West Texas to Houston, and the Basin Pipeline, a crude oil pipeline running from Jal, New Mexico, through Midland to Cushing, both of which are operated by another joint owner; and (iii) the receipt and delivery pipelines known as the West Texas Trunk System, which is located around the Midland terminal. The acquisition was accounted for under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from July 20, 2000.
In October 2000, we received a settlement notice from Atlantic Richfield Company for payment of a net aggregate amount of approximately $12.9 million in post-closing adjustments related to the purchase of ARCO. A large portion of the requested adjustment related to an indemnity for payment of accrued income taxes. In August 2001, we reached a settlement with Atlantic Richfield Company of $11.0 million for the post-closing adjustments.
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We recorded the settlement as an increase to the purchase price of ARCO. We paid the settlement amount to Atlantic Richfield Company on October 15, 2001.
On December 31, 2000, we completed an acquisition of pipeline assets from DEFS for $91.7 million, which included $0.7 million of acquisition related costs. The purchase included two natural gas liquids pipelines in East Texas: the Panola Pipeline, a pipeline from Carthage, Texas, to Mont Belvieu, Texas, and the San Jacinto Pipeline, a pipeline from Carthage to Longview, Texas. We also assumed a lease of a condensate pipeline from Carthage to Marshall, Texas. All three pipelines originate at DEFS’ East Texas Plant Complex in Panola County, Texas. We accounted for the acquisition of these assets under the purchase method of accounting.
On September 30, 2001, our subsidiaries completed the purchase of Jonah from Alberta Energy Company for $359.8 million. The acquisition served as our entry into the natural gas gathering industry. We recognized goodwill on the purchase of approximately $2.8 million. We accounted for the acquisition under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from September 30, 2001. We paid an additional $7.3 million on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. Under a contractual agreement, DEFS manages and operates Jonah on our behalf.
The following table allocates the estimated fair value of Jonah assets acquired on September 30, 2001, and includes the additional purchase adjustment paid on February 4, 2002 (in thousands):
The value assigned to intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production. We are amortizing the value assigned to intangible assets on a unit of production basis, based upon the actual throughput of the system over the expected total throughput for the contracts (averaging approximately 16 years).
On March 1, 2002, we completed the purchase of the Chaparral NGL system (“Chaparral”) for $132.4 million from Diamond-Koch II, L.P. and Diamond-Koch III, L.P., including acquisition related costs of approximately $0.4 million. We funded the purchase by a drawdown of our $500.0 million revolving credit facility (see Note 10. Debt). Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. Under a contractual agreement, DEFS manages and operates these assets on our behalf. We accounted for the acquisition of these assets under the purchase method of accounting. We allocated the purchase price to property, plant and equipment. Accordingly, the results of the acquisition are included in the consolidated financial statements from March 1, 2002.
On June 30, 2002, we completed the purchase of Val Verde for $444.2 million from Burlington Resources Gathering Inc., a subsidiary of Burlington Resources Inc., including acquisition related costs of approximately $1.2 million. We funded the purchase by drawing down $168.0 million under our $500.0 million revolving credit facility, $72.0 million under our 364-day revolving credit facility, and $200.0 million under a six-month term loan with SunTrust Bank (see Note 10. Debt). The remaining purchase price was funded through working capital sources of cash. The Val Verde system gathers CBM from the Fruitland Coal Formation of the San Juan Basin in
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New Mexico and Colorado. The system is one of the largest CBM gathering and treating facilities in the United States. Under a contractual agreement, DEFS manages and operates Val Verde on our behalf. We accounted for the acquisition of these assets under the purchase method of accounting. Accordingly, the results of the acquisition are included in the consolidated financial statements from June 30, 2002.
The following table allocates the estimated fair value of the Val Verde assets acquired on June 30, 2002 (in thousands):
The value assigned to intangible assets relates to fixed-term contracts with customers. We are amortizing the value assigned to intangible assets on a unit of production basis, based upon the actual throughput of the system over the expected total throughput for the contracts (averaging approximately 20 years).
The following table presents our unaudited pro forma results as though the acquisitions of Jonah and Val Verde occurred at the beginning of 2001 or 2002 (in thousands, except per Unit amounts). The unaudited pro forma results give effect to certain pro forma adjustments including depreciation and amortization expense adjustments of property, plant and equipment and intangible assets based upon the purchase price allocations, interest expense related to financing the acquisitions, amortization of debt issue costs and the removal of income tax effects in historical results of operations. The pro forma results do not include operating efficiencies or revenue growth from historical results.
The summarized pro forma information has been prepared for comparative purposes only. It is not intended to be indicative of the actual operating results that would have occurred had the acquisitions been consummated at the beginning of 2001 or 2002, or the results which may be attained in the future.
NOTE 6. EQUITY INVESTMENTS
The acquisition of the ARCO assets in July 2000 included ARCO’s 50% ownership interest in Seaway, which owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston areas. Seaway is a partnership between a subsidiary of TCTM, TEPPCO Seaway, L.P. (“TEPPCO Seaway”), and ConocoPhillips. TCTM purchased the 50% ownership interest in Seaway on July 20, 2000, and transferred the investment to TEPPCO Seaway. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of the Seaway partnership. From July 20, 2000, through May 2002, TEPPCO Seaway received 80% of revenue and expense of Seaway. From June 2002 through May 2006, TEPPCO Seaway will receive 60% of revenue and expense of Seaway. Thereafter, the sharing ratio becomes 40% of revenue and
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expense to TEPPCO Seaway. For the year ended December 31, 2002, our portion of equity earnings on a pro-rated basis averaged approximately 67%.
In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a subsidiary of CMS Energy Corporation, and Marathon Ashland Petroleum LLC (“Marathon”) to form Centennial Pipeline LLC (“Centennial”). Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to Illinois. Through December 31, 2002, each participant owned a one-third interest in Centennial. During the years ended December 31, 2002 and 2001, we contributed approximately $10.9 million and $70.0 million, respectively, for our investment in Centennial. These amounts are included in the equity investment balance at December 31, 2002 and 2001.
We use the equity method of accounting to report our investments in Seaway and Centennial. Summarized combined income statement data for Seaway and Centennial for the years ended December 31, 2002, and 2001, is presented below (in thousands):
Summarized combined balance sheet data for Seaway and Centennial as of December 31, 2002, and 2001, is presented below (in thousands):
Our investment in Seaway at December 31, 2002, and 2001, includes an excess net investment amount of $25.5 million. Excess investment is the amount by which our investment balance exceeds our proportionate share of the net assets of the investment. Prior to January 1, 2002, and our adoption of SFAS 142, we were amortizing the excess investment in Seaway using the straight-line method over 20 years.
NOTE 7. RELATED PARTY TRANSACTIONS
We have no employees and are managed by the Company, a wholly owned subsidiary of DEFS. Duke Energy holds an approximate 70% interest in DEFS and ConocoPhillips holds the remaining 30%. According to the Partnership Agreements, the Company is entitled to reimbursement of all direct and indirect expenses related to our business activities (see Note 1. Partnership Organization).
For the years ended December 31, 2002, 2001, and 2000, direct expenses incurred by the Company of $69.6 million, $68.2 million and $50.4 million, respectively, were charged to us by DEFS. Substantially all such costs were related to payroll and payroll related expenses. For the years ended December 31, 2002, 2001, and 2000, expenses for administrative services and overhead allocated to us by Duke Energy and its affiliates were $0.8 million, $0.6 million and $0.8 million, respectively.
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Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado, LLC (“TEPPCO Colorado”) and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Revenues recognized from the fractionation facilities totaled $7.4 million, $7.4 million and $7.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS. Expenses related to the Operation and Maintenance Agreement totaled $0.9 million, $0.9 million and $0.9 million for the years ended December 31, 2002, 2001 and 2000, respectively.
Included with crude oil assets purchased from DEFS effective November 1, 1998, was the Wilcox NGL Pipeline located along the Texas Gulf Coast. The Wilcox NGL Pipeline transports NGLs for DEFS from two of their processing plants and is currently supported by a throughput agreement with DEFS through 2005. The fees paid to us by DEFS under the agreement totaled $1.2 million, $1.2 million and $1.1 million for the years ended December 31, 2002, 2001 and 2000, respectively. The Panola Pipeline and San Jacinto Pipeline were purchased on December 31, 2000, from DEFS for $91.7 million. These pipelines originate at DEFS’ East Texas Plant Complex in Panola County, Texas. For the years ended December 31, 2002 and 2001, revenues recognized included $12.0 million and $13.9 million, respectively, from a subsidiary of DEFS for NGL transportation fees on the Panola and San Jacinto Pipelines.
On July 20, 2000, we, through TCTM, acquired a 50% ownership interest in Seaway. ConocoPhillips owns the remaining 50% interest in Seaway. TEPPCO Crude Pipeline, L.P. is the operator of this pipeline. During the years ended December 31, 2002, 2001 and 2000, we billed Seaway $7.1 million, $7.0 million and $2.9 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, during the years ended December 31, 2002, 2001 and 2000, we billed Seaway $2.1 million, $2.1 million and $0.9 million, respectively, for indirect management fees for operating Seaway.
Effective May 2001, we entered into an agreement with DEFS to commit sole utilization of our Providence terminal to DEFS. We operate the terminal and provide propane loading services to DEFS. During the years ended December 31, 2002 and 2001, revenues of $2.3 million and $1.5 million from DEFS, respectively, were recognized pursuant to this agreement.
On September 30, 2001, we completed the acquisition of Jonah. The Jonah assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the years ended December 31, 2002, and 2001, we recognized $3.3 million and $0.6 million, respectively, of expense related to the management of the Jonah assets by DEFS.
On March 1, 2002, we completed the acquisition of the Chaparral NGL system. The Chaparral assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the year ended December 31, 2002, we recognized $1.7 million of expenses related to the management of the Chaparral assets by DEFS.
On June 30, 2002, we completed the acquisition of Val Verde. The Val Verde assets are managed and operated by employees of DEFS under a contractual agreement under which DEFS is reimbursed for its actual costs. During the year ended December 31, 2002, we recognized $1.2 million of expenses related to the management of the Val Verde assets by DEFS.
In August 2000, TE Products entered into agreements with PEPL and Marathon to form Centennial (see Note 6. Equity Investments). At December 31, 2002, TE Products had a one-third ownership interest in Centennial. TE Products has entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs and pipeline connection in Beaumont, Texas. For the year ended December 31, 2002, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $0.3
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million. TE Products also has a joint tariff with Centennial to deliver products at TE Products’ locations using Centennial’s pipeline as part of the delivery route to connecting carriers. TE Products, as the delivering pipeline, invoices the shippers for the entire delivery rate, records only the net rate attributable to it as transportation revenues and records a liability for the amounts due to Centennial for its share of the tariff. At December 31, 2002, we have a payable balance of $1.0 million to Centennial for its share of the joint tariff deliveries. In addition, TE Products performs ongoing construction services for Centennial and bills Centennial for labor and other costs to perform the construction. At December 31, 2002, TE Products has a receivable of $1.9 million due from Centennial for reimbursement of construction services provided to Centennial.
NOTE 8. INVENTORIES
Inventories are valued at the lower of cost (based on weighted average cost method) or market. The major components of inventories were as follows (in thousands):
The costs of inventories did not exceed market values at December 31, 2002 and 2001.
NOTE 9. PROPERTY, PLANT AND EQUIPMENT
Major categories of property, plant and equipment were as follows (in thousands):
Depreciation expense on property, plant and equipment was $56.0 million, $39.5 million and $33.0 million for the years ended December 31, 2002, 2001 and 2000, respectively.
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NOTE 10. LONG TERM DEBT
Senior Notes
On January 27, 1998, TE Products completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at a premium.
The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank on a parity with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2002, TE Products was in compliance with the covenants of the TE Products Senior Notes.
On February 20, 2002, we received $494.6 million in net proceeds, after underwriting discount, from the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. We used the proceeds from the offering to reduce a portion of the outstanding balances of our credit facilities, including those issued in connection with the acquisition of Jonah. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2002, we were in compliance with the covenants of these Senior Notes.
At December 31, 2002 and 2001, the estimated fair value of the Senior Notes was approximately $914.9 million and $362.0 million, respectively. Market prices for recent transactions and rates currently available to us for debt with similar terms and maturities were used to estimate fair value.
We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above. See Note 4. Derivative Financial Instruments.
Other Long Term Debt and Credit Facilities
On July 14, 2000, we entered into a $75.0 million term loan and a $475.0 million revolving credit facility (“Three Year Facility”). On July 21, 2000, we borrowed $75.0 million under the term loan and $340.0 million under the Three Year Facility. The funds were used to finance the acquisition of the ARCO assets (see Note 5. Acquisitions) and to refinance existing bank credit facilities, other than the Senior Notes. The term loan was repaid from proceeds received from the issuance of additional Limited Partner Units on October 25, 2000. On April 6, 2001, the Three Year Facility was amended to provide for revolving borrowings of up to $500.0 million for a period of three years including the issuance of letters of credit of up to $20.0 million. The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA (earnings before interest expense, income
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tax expense and depreciation and amortization expense) and minimum fixed charge coverage ratios. On February 20, 2002, we repaid $115.7 million of the then outstanding balance of the Three Year Facility with proceeds from the issuance of our 7.625% Senior Notes. On March 1, 2002, we borrowed $132.0 million under the Three Year Facility to finance the acquisition of the Chaparral NGL system. On March 22, 2002, we repaid a portion of the Three Year Facility with proceeds we received from the issuance of additional Limited Partner Units (see Note 11. Partners’ Capital). To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Three Year Facility was amended to increase the maximum permitted debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. For the twelve month period ending June 30, 2002, the maximum permitted ratio was 5.5-to-1 on a pro forma basis. For the twelve month period ending September 30, 2002, the maximum permitted ratio was 5.0-to-1 on a pro forma basis. At December 31, 2002, the maximum permitted debt-to-EBITDA ratio under our revolving credit facility returned to its pre-amendment level of 4.5-to-1. We then drew down the existing capacity of the Three Year Facility and acquired the Val Verde assets. During the fourth quarter of 2002, we repaid $68.0 million of the outstanding balance of the Three Year Facility with proceeds from our November 2002 equity offering (see Note 11. Partners’ Capital) and proceeds from the termination of our interest rate swaps (see Note 4. Derivative Financial Instruments). At December 31, 2002, $432.0 million was outstanding under the Three Year Facility at a weighted average interest rate of 2.5%. As of December 31, 2002, we were in compliance with the covenants contained in this credit agreement.
We have entered into an interest rate swap agreement to hedge our exposure to increases in interest rates on the Three Year Facility discussed above. See Note 4. Derivative Financial Instruments.
Short Term Credit Facilities
On April 6, 2001, we entered into a 364-day, $200.0 million revolving credit agreement (“Short-term Revolver”). The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contains restrictive financial covenants that require us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On March 28, 2002, the Short-term Revolver was extended for an additional period of 364 days, ending in March 2003. To facilitate our financing of a portion of the purchase price of the Val Verde assets, on June 27, 2002, the Short-term Revolver was amended to increase the maximum permitted debt-to-EBITDA ratio covenant to allow us to incur additional indebtedness. For the twelve month period ending June 30, 2002, the maximum permitted ratio was 5.5-to-1 on a pro forma basis. For the twelve month period ending September 30, 2002, the maximum permitted ratio was 5.0-to-1 on a pro forma basis. At December 31, 2002, the maximum permitted debt-to-EBITDA ratio under our revolving credit facility returned to its pre-amendment level of 4.5-to-1. We then drew down $72.0 million under the Short-term Revolver. In the fourth quarter of 2002, we repaid the existing amounts outstanding under the Short-term Revolver with proceeds we received from the issuance of Limited Partner Units in November and December 2002. At December 31, 2002, no amounts were outstanding under the Short-term Revolver. As of December 31, 2002, we were in compliance with the covenants contained in this credit agreement. In February 2003, we gave notice that we will not renew the Short-term Revolver. As a result, the facility will expire on March 27, 2003.
On September 28, 2001, we entered into a $400.0 million credit facility with SunTrust Bank (“Bridge Facility”) payable in June 2002. We borrowed $360.0 million under the Bridge Facility to acquire the Jonah assets (see Note 5. Acquisitions). During the fourth quarter of 2001, we repaid $160.0 million of the outstanding principal from proceeds received from the issuance of Limited Partner Units in November 2001. On February 5, 2002, we drew down an additional $15.0 million under the Bridge Facility. On February 20, 2002, we repaid the outstanding balance of the Bridge Facility of $215.0 million with proceeds from the issuance of the 7.625% Senior Notes and canceled the facility.
On June 27, 2002, we entered into a $200.0 million six-month term loan with SunTrust Bank (“Six-Month Term Loan”) payable in December 2002. We borrowed $200.0 million under the Six-Month Term Loan to acquire
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the Val Verde assets (see Note 5. Acquisitions). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement contained restrictive financial covenants that required us to maintain a minimum level of partners’ capital as well as maximum debt-to-EBITDA and minimum fixed charge coverage ratios. On July 11, 2002, we repaid $90.0 million of the outstanding principal from proceeds primarily received from the issuance of Limited Partner Units in July 2002. On September 10, 2002, we repaid the remaining outstanding balance of $110.0 million with proceeds received from the issuance of Limited Partner Units in September 2002 (see Note 11. Partners’ Capital), and canceled the facility.
The following table summarizes the principal amounts outstanding under our credit facilities as of December 31, 2002 and 2001 (in thousands):
NOTE 11. PARTNERS’ CAPITAL
On February 6, 2001, we sold in an underwritten public offering 2.0 million Limited Partner Units at $25.50 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $48.7 million and were used to reduce borrowings under the Three Year Facility. On March 6, 2001, 250,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on February 6, 2001. Proceeds from that sale totaled $6.1 million and were used for general purposes.
On November 14, 2001, we sold in an underwritten public offering 5.5 million Limited Partner Units at $34.25 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $180.3 million and were used to repay $160.0 million under the Bridge Facility that was used to fund the Jonah acquisition. The remaining proceeds were used to finance contributions to Centennial and for other capital expenditures.
On March 22, 2002, we sold in an underwritten public offering 1.92 million Limited Partner Units at $31.18 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $57.3 million and were used to repay $50.0 million of the outstanding balance on the Three Year Facility, with the remaining amount being used for general purposes.
On July 11, 2002, we sold in an underwritten public offering 3.0 million Limited Partner Units at $30.15 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $86.6 million and were used to reduce borrowings under our Six-Month Term Loan. On August 14, 2002, 175,000 Units were sold
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upon exercise of the underwriters’ over-allotment option granted in connection with the offering on July 11, 2002. Proceeds from that sale totaled $5.1 million and were used for general purposes.
On September 6, 2002, we sold in an underwritten public offering 3.8 million Limited Partner Units at $29.72 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $108.1 million and were used to reduce borrowings under our Six-Month Term Loan. On September 19, 2002, 570,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on September 6, 2002. Proceeds from that sale totaled $16.2 million and were used to reduce borrowings under our Short-term Revolver.
On November 7, 2002, we sold in an underwritten public offering 3.3 million Limited Partner Units at $26.83 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $84.8 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility. On December 4, 2002, 495,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on November 7, 2002. Proceeds from that sale totaled $12.7 million and were used to reduce borrowings under our Short-term Revolver and Three Year Facility.
NOTE 12. CONCENTRATIONS OF 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 customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. We thoroughly analyze our customers’ historical and future credit positions prior to extending credit. 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 and guarantees.
For the years ended December 31, 2002, 2001 and 2000, we had one customer from the Upstream Segment, Valero Energy Corp., which accounted for 16%, 14% and 12%, respectively, of our total consolidated revenues.
The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and notes payable approximates their fair value due to their short-term nature.
NOTE 13. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH
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 sole discretion. Pursuant to the Partnership Agreement, the Company receives incremental incentive cash distributions when cash distributions exceed certain target thresholds as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table reflects the allocation of total distributions paid for the years ended December 31, 2002, 2001 and 2000 (in thousands, except per Unit amounts).
On February 7, 2003, we paid a cash distribution of $0.60 per Limited Partner Unit and Class B Unit for the quarter ended December 31, 2002. The fourth quarter 2002 cash distribution totaled $46.5 million.
NOTE 14. UNIT-BASED COMPENSATION
1994 Long Term Incentive Plan
During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994 LTIP provides certain key employees with an incentive award whereby a participant is granted an option to purchase Limited Partner Units. These same employees are also granted a stipulated number of Performance Units, the cash value of which may be used to pay for the exercise of the respective Limited Partner Unit options awarded. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted.
When our calendar year earnings per unit (exclusive of certain special items) exceeds a stated threshold, each participant receives a credit to their respective Performance Unit account equal to the earnings per unit excess multiplied by the number of Performance Units awarded. The balance in the Performance Unit account may be used to offset the cost of exercising Limited Partner Unit options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant. We accrue compensation expense for the Performance Units awarded annually based upon the terms of the plan discussed above.
Under the agreement for such Limited Partner Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. Options may also be exercised by normal means once vesting requirements are met. A summary of Performance Units and Limited Partner Unit options granted under the terms of the 1994 LTIP is presented below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
We have not granted options for any periods presented. For options outstanding, we followed the intrinsic value method for recognizing stock-based compensation expense. The exercise price of all options awarded under the 1994 LTIP equaled the market price of our Limited Partner Units on the date of grant. Accordingly, we recognized no compensation expense at the date of grant. Had compensation expense been determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation, compensation expense related to option grants would have totaled $5,570, $118,820 and $202,634 during the years ended December 31, 2002, 2001 and 2000, respectively. The disclosures as required by SFAS 123 are not representative of the effects on pro forma net income for future years as options vest over several years and additional awards may be granted in subsequent years.
For purposes of determining compensation costs using the provisions of SFAS 123, the fair value of option grants was determined using the Black-Scholes option-valuation model. The key input variables used in valuing the options were:
1999 and 2002 Phantom Unit Plans
Effective September 1, 1999, the Company adopted the Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 PURP”). Effective June 1, 2002 the Company adopted the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan (“2002 PURP”). The 1999 PURP and the 2002 PURP provide key employees with incentive awards whereby a participant is granted phantom units. These phantom units are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at stated redemption dates. The fair market value of each phantom unit is equal to the closing price of a Limited Partnership Unit as reported on the New York Stock Exchange on the redemption date.
Under the agreement for the phantom units, each participant will vest 10% of the number of phantom units initially granted under his or her award at the end of each of the first four years and will vest the final 60% at the end of the fifth year. Each participant is required to redeem their units as they vest. They are also entitled to quarterly cash distributions equal to the product of the number of phantom units outstanding for the participant and the
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amount of the cash distribution that we paid per unit to Limited Partner Unitholders. A total of 58,800 phantom units have been granted under the 1999 PURP, of which 30,330 remain outstanding at December 31, 2002. A total of 71,400 phantom units have been granted under the 2002 PURP, of which all 71,400 remain outstanding at December 31, 2002. We accrue compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above.
2000 Long Term Incentive Plan
Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom Limited Partner Units granted under the award multiplied by (3) the average of the closing prices of a Limited Partner Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. The performance percentage may not exceed 150%. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period. At December 31, 2002, phantom Limited Partner Units outstanding were 22,300, 24,013 and 18,425 for awards granted in 2002, 2001 and 2000, respectively.
Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that in its discretion the Compensation Committee of the General Partner may exclude gains or losses from extraordinary, unusual or non-recurring items. Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment, plus products and crude oil linefill and the gross value of intangibles and equity investments. Our cost of capital is approved by the Committee at the date of award grant.
In addition to the payment described above, during the performance period, the General Partner will pay to the Participant the amount of cash distributions that we would have paid to our Unitholders had the participant been the owner of the number of Limited Partner Units equal to the number of phantom Limited Partner Units granted to the participant under this award. The maximum potential payout under the 2000 LTIP is 150% of phantom units awarded. We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 15. OPERATING LEASES
We utilize leased assets in several areas of our operations. Total rental expense during the years ended December 31, 2002, 2001 and 2000 was $14.2 million, $10.8 million and $10.7 million, respectively. The following table sets forth our minimum rental payments under our various operating leases for the years ending December 31 (in thousands):
NOTE 16. EMPLOYEE BENEFITS
Retirement Plans
Prior to the transfer of the General Partner interest from Duke Energy to DEFS on April 1, 2000, the Company’s employees participated in the Duke Energy Retirement Cash Balance Plan (“Duke Energy RCBP”), which is a noncontributory, trustee-administered pension plan. In addition, certain executive officers participated in the Duke Energy Executive Cash Balance Plan (“Duke Energy ECBP”), which is a noncontributory, nonqualified, defined benefit retirement plan. The Duke Energy ECBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. Effective January 1, 1999, the benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit based upon pay credits and current interest credits. The pay credits are based on a participant’s salary, age, and service. As part of the change in ownership, the Company is no longer responsible for the funding of the liabilities associated with these plans.
Effective April 1, 2000, the Company adopted the TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) and the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”). The benefits and provisions of these plans are substantially identical to the Duke Energy RCBP and the Duke Energy ECBP previously in effect prior to April 1, 2000.
The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2002, 2001 and 2000, and for the Duke Energy RCBP and the Duke Energy ECBP for the year ended December 31, 2000 were as follows (in thousands):
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Other Postretirement Benefits
Prior to April 1, 2000, the Company’s employees were provided with certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis through Duke Energy (“Duke Energy OPB”). Employees became eligible for these benefits if they had met certain age and service requirements at retirement, as defined in the plans. As part of the change in ownership, the Company is no longer responsible for the funding of the liabilities associated with these plans. Effective January 1, 2001, the Company provided its own plan for health care benefits for retired employees (“TEPPCO OPB”).
The Company provides a fixed dollar contribution towards retired employee medical costs. The fixed dollar contribution does not increase from year to year. The retiree pays all health care cost increases due to medical inflation.
The components of net postretirement benefits cost for the Duke Energy OPB for the year ended December 31, 2000, and for the TEPPCO OPB for the years ended December 31, 2002 and 2001, were as follows (in thousands):
The weighted average assumptions used in the actuarial computations for the retirement plans and other postretirement benefit plans for the years ended December 31, 2002 and 2001 are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table sets forth the Company’s pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2002 and 2001 (in thousands):
Other Plans
DEFS also sponsors an employee savings plan, which covers substantially all employees. Plan contributions on behalf of the Company of $2.8 million, $3.1 million and $2.2 million were expensed during the years ended December 31, 2002, 2001 and 2000, respectively.
NOTE 17. COMMITMENTS AND CONTINGENCIES
In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et. al. v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et. al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In
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their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. We have filed an answer to both complaints, denying the allegations, as well as various other motions. These cases are not covered by insurance. Discovery is ongoing, and we are defending ourselves vigorously against the lawsuits. The plaintiffs have not stipulated the amount of damages that they are seeking in the suit. We cannot estimate the loss, if any, associated with these pending lawsuits.
On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et. al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiff’s property, leaked toxic products onto the plaintiff’s property. The plaintiffs further contend that this leak caused damages to the plaintiffs. We have filed an answer to the plaintiff’s petition denying the allegations. The plaintiffs have not stipulated the amount of damages they are seeking in the suit. We are defending ourselves vigorously against the lawsuit. We cannot estimate the damages, if any, associated with this pending lawsuit; however, this case is covered by insurance.
On April 19, 2002, we, through our subsidiary TEPPCO Crude Oil, L.P., filed a declaratory judgment action in the U.S. District Court for the Western District of Oklahoma against D.R.D. Environmental Services, Inc. (“D.R.D.”) seeking resolution of billing and other contractual disputes regarding potential overcharges for environmental remediation services provided by D.R.D. On May 28, 2002, D.R.D. filed a counterclaim for alleged breach of contract in the amount of $2,243,525, and for unspecified damages for alleged tortious interference with D.R.D.’s contractual relations with DEFS. We have denied the counterclaims. Discovery is ongoing. If D.R.D. should be successful, management believes that a substantial portion of the $2,243,525 breach of contract claim will be covered under an indemnity from DEFS. We cannot predict the outcome of the litigation against us; however, we are defending ourselves vigorously against the counterclaim. 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 addition to the litigation 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 lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial position, results of operations or cash flows.
In February 2002, a producer on the Jonah system sent a letter to Alberta Energy Company implying that as a result of our acquisition of the Jonah system, it may have a right to acquire all or a portion of the assets comprising the Jonah system pursuant to an alleged right of first refusal in a gas gathering agreement between the producer and Jonah. Subsidiaries of Alberta Energy Company have agreed to indemnify us against losses resulting from any breach of representations concerning the absence of third party rights in connection with our acquisition of the entity that owns the Jonah system. We believe that we have adequate legal defenses if the producer should assert a claim, and we also believe that no right of first refusal on any of the underlying Jonah system assets has been triggered.
Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. Although we believe our operations are in material compliance with applicable environmental laws and regulations, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure you that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. We believe that changes in environmental laws and regulations will not have a material adverse effect on our financial position, results of operations or cash flows in the near term.
TEPPCO PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In 1994, we entered into an Agreed Order with the Indiana Department of Environmental Management (“IDEM”) that resulted in the implementation of a remediation program for groundwater contamination attributable to our operations at the Seymour, Indiana, terminal. In 1999, the IDEM approved a Feasibility Study, which includes our proposed remediation program. We expect the IDEM to issue a Record of Decision formally approving the remediation program. After the Record of Decision is issued, we will enter into a subsequent Agreed Order for the continued operation and maintenance of the remediation program. We have an accrued liability of $0.4 million at December 31, 2002, for future remediation costs at the Seymour terminal. We do not expect that the completion of the remediation program will have a future material adverse effect on our financial position, results of operations or cash flows.
In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. This contamination may be attributable to our operations, as well as adjacent petroleum terminals operated by other companies. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this containment phase. At December 31, 2002, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program that we have proposed will have a future material adverse effect on our financial position, results of operations or cash flows.
At December 31, 2002, we have an accrued liability of $5.6 million and a receivable of $4.2 million from DEFS related to various TCTM sites requiring environmental remediation activities. The receivable is based on a contractual indemnity obligation we received in connection with our acquisition of assets from a DEFS affiliate in November 1998. The indemnity relates to future environmental remediation activities attributable to operations of these assets prior to our acquisition. Under this indemnity obligation, we are responsible for the first $3.0 million in specified environmental liabilities, and DEFS is responsible for those environmental liabilities in excess of $3.0 million, up to a maximum amount of $25.0 million. The majority of the receivable from DEFS relates to remediation activities at the Velma crude oil site in Stephens County, Oklahoma. The accrued liability balance at December 31, 2002, also includes an accrual of $2.3 million related to the Shelby crude oil site in Stephens County, Oklahoma. At December 31, 2002, it is uncertain if these costs related to Shelby are covered under the indemnity obligation from DEFS. We are currently in discussions with DEFS regarding these matters. We do not expect that the completion of remediation programs associated with TCTM activities will have a future material adverse effect on our financial position, results of operations or cash flows.
Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2002, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. Each of the participants in Centennial, including TE Products, originally guaranteed one-third of Centennial’s debt up to a maximum amount of $50.0 million. During the third quarter of 2002, PEPL, one of the participants in Centennial, was downgraded by Moody’s and Standard & Poors to below investment grade, which resulted in PEPL being in default under its portion of the Centennial guaranty. Effective September 27, 2002, TE Products and Marathon increased their guaranteed amounts to one-half of the debt of Centennial, up to a maximum amount of $75.0 million each, to avoid a default on the Centennial debt. As compensation to TE Products and Marathon for providing their additional guarantees, PEPL was required to pay interest at a rate of 4% per annum to each of TE Products and Marathon on the portion of the additional guaranty that each has provided for PEPL.
In February 2000, we entered into a joint marketing and development alliance with Louis Dreyfus Plastics Corporation, now known as Louis Dreyfus Energy Services, L.P. (“Louis Dreyfus”), in which our Mont Belvieu LPGs storage and transportation shuttle system services were jointly marketed by Louis Dreyfus and TE Products. The purpose of the alliance was to expand services to the upper Texas Gulf Coast energy marketplace by increasing pipeline throughput and the mix of products handled through the existing system and establishing new receipt and delivery connections. The alliance was a service-oriented, fee-based venture with no commodity trading activity. TE Products operated the facilities for the alliance. Under the alliance, Louis Dreyfus invested $6.1 million for expansion projects at Mont Belvieu. The alliance also stipulated that if certain earnings thresholds were achieved, a
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
partnership between TE Products and Louis Dreyfus was to be created effective January 1, 2003. All terms and earnings thresholds have been met; therefore, we will be contributing our Mont Belvieu assets to the newly formed partnership. The economic terms of the partnership are the same as those under the joint development and marketing alliance. TE Products will continue to operate the facilities for the partnership. The net book value of the Mont Belvieu assets that we are contributing to the partnership is approximately $68.2 million. Our interest in the partnership will be accounted for as an equity investment.
Rates of interstate refined petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI Index”). Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI - 1% to PPI. In the alternative, interstate refined petroleum products and crude oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements between shippers and refined petroleum products and crude oil pipeline companies that the rate is acceptable (“Settlement Rates”).
On May 11, 1999, TE Products filed an application with the FERC requesting permission to charge Market-Based Rates for substantially all refined products transportation tariffs. On July 31, 2000, the FERC issued an order granting TE Products Market-Based Rates in certain markets and set for hearing TE Products’ application for Market-Based Rates in certain destination markets and origin markets. After the matter was set for hearing, TE Products and the protesting shippers entered into a settlement agreement resolving their respective differences. On April 25, 2001, the FERC issued an order approving the offer of settlement. As a result of the settlement, TE Products recognized approximately $1.7 million of previously deferred transportation revenue in the second quarter of 2001. As a part of the settlement, TE Products withdrew the application for Market-Based Rates to the Little Rock, Arkansas, and Arcadia and Shreveport-Arcadia, Louisiana, destination markets, which are currently subject to the PPI Index. As a result, we made refunds of approximately $1.0 million in the third quarter of 2001 for those destination markets.
Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2002, TCTM and TE Products had approximately 2.7 million barrels and 17.4 million barrels, respectively, of products in their custody that was owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance adequate to cover product losses through circumstances beyond our control.
NOTE 18. SEGMENT DATA
We have three reporting segments: transportation and storage of refined products, LPGs and petrochemicals, which operates as the Downstream Segment; gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals, which operates as the Upstream Segment; and gathering of natural gas, fractionation of NGLs and transportation of NGLs, which operates as the Midstream Segment. The amounts indicated below as “Partnership and Other” relate primarily to intercompany eliminations and assets that we hold that have not been allocated to any of our reporting segments.
Effective January 1, 2002, we realigned our three business segments to reflect our entry into the natural gas gathering business and the expanded scope of NGLs operations. We transferred the fractionation of NGLs, which was previously reflected as part of the Downstream Segment, to the Midstream Segment. The operation of NGL pipelines, which was previously reflected as part of the Upstream Segment, was also transferred to the Midstream Segment. We have adjusted our period-to-period comparisons to conform with the current presentation.
Our Downstream Segment includes the interstate transportation, storage and terminaling of petroleum products and LPGs and intrastate transportation of petrochemicals. Revenues are earned from transportation and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
storage of refined products and LPGs, storage and short-haul shuttle transportation of LPGs at the Mont Belvieu complex, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Our Downstream Segment’s pipeline system extends from southeast Texas through the central and midwestern United States to the northeastern United States, and is one of the largest pipeline common carriers of refined petroleum products and LPGs in the United States. Our Downstream Segment also includes our equity investment in Centennial.
Our Upstream Segment includes the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. Our Upstream Segment also includes the equity earnings from our investment in Seaway. Seaway is a large diameter pipeline that transports crude oil from the U.S. Gulf Coast to Cushing, Oklahoma, a central crude oil distribution point for the Central United States.
Our Midstream Segment includes the fractionation of NGLs in Colorado; the ownership and operation of two trunkline NGL pipelines in South Texas and two NGL pipelines in East Texas; and the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, which was acquired by our subsidiaries on September 30, 2001. This segment also includes Chaparral, which we acquired on March 1, 2002. Chaparral is an NGL pipeline system that extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage in Mont Belvieu. On June 30, 2002, we acquired the Val Verde system, which gathers CBM from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado, and is one of the largest CBM gathering and treating facilities in the United States. The results of operations of the Jonah, Chaparral, and Val Verde acquisitions are included in periods subsequent to September 30, 2001, March 1, 2002, and June 30, 2002, respectively (See Note 5. Acquisitions).
The tables below include financial information by reporting segment for the years ended December 31, 2002, 2001 and 2000 (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table provides the total assets for each segment as of December 31, 2002, 2001 and 2000 (in thousands):
The following table reconciles the segments total to consolidated net income (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 19. COMPREHENSIVE INCOME
SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments, and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the years ended December 31, 2002 and 2001, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which is designated as a cash flow hedge. Changes in the fair value of the cash flow hedge, to the extent the hedge is effective, are recognized in other comprehensive income until the hedge interest costs are recognized in earnings. The table below reconciles reported net income to total comprehensive income for the years ended December 31, 2002, 2001 and 2000 (in thousands).
The accumulated balance of other comprehensive loss related to cash flow hedges is as follows (in thousands):
NOTE 20. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
In connection with our issuance of Senior Notes on February 20, 2002, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, our significant operating subsidiaries, issued unconditional guarantees of our debt securities. Effective with the acquisition of the Val Verde assets on June 30, 2002, our subsidiary, Val Verde Gas Gathering Company, L.P. also became a significant operating subsidiary and issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the “Guarantor Subsidiaries.”
The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting.
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NOTE 21. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (1)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 22. SUBSEQUENT EVENTS
On January 30, 2003, we received $197.3 million in net proceeds, after underwriting discount, from the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and will be accreted to their face value over the term of the notes. We used $182.0 million of the proceeds from the offering to reduce the outstanding principal on the Three Year Facility to $250.0 million. The balance of the proceeds of $15.3 million was used for general purposes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. Our Guarantor Subsidiaries issued unconditional guarantees of these Senior Notes (see Note 20. Supplemental Condensed Consolidating Financial Information).
In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years. On February 10, 2003, TE Products acquired an additional interest in Centennial from PEPL for $20.0 million, increasing its percentage ownership in Centennial to 50%. Upon closing of the acquisition, TE Products and Marathon each own a 50% ownership interest in Centennial. In connection with the acquisition of the additional interest in Centennial, the guaranty agreement between TE Products, Marathon and PEPL was terminated. TE Products’ guaranty of up to a maximum of $75.0 million of Centennial’s debt remains in effect.
INDEPENDENT AUDITORS’ REPORT ON CONSOLIDATED FINANCIAL STATEMENT
SCHEDULE
To the Partners of
TEPPCO Partners, L.P.:
Under date of January 22, 2003, except as to note 22 which is as of February 10, 2003, we reported on the consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2002 and 2001, and the related consolidated statements of income, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2002. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated financial statement schedule. This consolidated financial statement schedule is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the consolidated financial statement schedule based on our audits.
In our opinion, the consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
KPMG LLP
Houston, Texas
January 22, 2003
S-1
SCHEDULE II
TEPPCO PARTNERS, L.P.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 2000, 2001 AND 2002
(in thousands)
S-2
Exhibit Index