Item 3. Legal Proceedings
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. On January 27, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs and the Richards plaintiffs dismissing all of these plaintiffs’ claims. The settlement terms include a $2.0 million payment to the plaintiffs, which has been accrued for in our consolidated
financial statements. The terms of the settlements did not have a material adverse effect on our financial position, results of operations or cash flows.
Although we did not settle with all plaintiffs and we therefore remain named parties in the Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed to indemnify us for all remaining claims asserted against us. Consequently, we do not believe that the outcome of these remaining claims will have a material adverse effect on our financial position, results of operations or cash flows.
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 plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’ petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The plaintiffs have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance. 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 May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are alleged to have suffered damages as the result of alleged exposure to asbestos-containing products and materials. According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual. The individual’s claims involve numerous employers and alleged job sites. The General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is uncertain at this time whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit. We cannot estimate the loss, if any, associated with this pending lawsuit. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On April 2, 2003, Centennial was served with a petition in a matter styled Adams, et al. v. Centennial Pipeline Company LLC, et al. This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill. The plaintiffs allege personal injuries, allergies, birth defects, cancer and death. The underground injection well has been in operation since May 1976. Based upon current information, Centennial appears to be a de minimis contributor, having used the disposal site during the two month time period of December 2001 to January 2002. Marathon has been handling this matter for Centennial under its operating agreement with Centennial. TE Products has a 50% ownership interest in Centennial. On November 30, 2004, the court approved a class settlement. The time period for parties to appeal this settlement has not expired, however, and the settlement will not be final until it does so. If the approved class settlement becomes final, the terms of the settlement will not have a material adverse effect on our financial position, results of operations or cash flows.
On December 16, 2003, Centennial, the General Partner, the Partnership and other Partnership entities were named as defendants in a lawsuit in the 128th District Court of Orange County, Texas, styled Elwood Karr et al. v. Centennial Pipeline, LLC et al. In this case, the plaintiffs contend that our pipeline leaked toxic substances on their property, causing them property damage. On October 29, 2004, the parties entered into a Settlement Agreement, dismissing all claims. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.
On February 4, 2005, we received a letter notifying us of a claim for approximately $1.45 million in damages allegedly due to a shipper being delivered off-specification gasoline during November 2004. We are contesting liability for this matter, and to the extent there may be liability, we would seek reimbursement from the third party refiner who supplied the gasoline into our pipeline system. We do not believe that the outcome of this matter will have a future material adverse effect on our consolidated financial position, results of operations or cash flows.
On February 7, 2005, we received a letter from BP Amoco’s counsel placing us on notice of a lawsuit filed by ConocoPhillips against BP Amoco Seaway Products Pipeline Company. Pursuant to provisions of the Amended and Restated Purchase Agreement dated May 10, 2000, between us and ARCO (BP Amoco), BP Amoco requested indemnity should BP Amoco have any liability to ConocoPhillips. The litigation arises out of an income tax liability alleged by ConocoPhillips due to a partnership merger. The plaintiff estimates the income tax liability to be $3,964,788. We have requested information from BP Amoco that will allow us to assess liability, if any, that we may have in this matter. We do not believe that the outcome of this lawsuit will have a future material adverse effect on our consolidated 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 Units are listed and traded on the New York Stock Exchange under the symbol “TPP”. The high and low trading prices of our Units in 2004 and 2003, respectively, as reported in The New York Times, were as follows:
On February 25, 2005, the closing market price for our Units was $43.10 per Unit. Based on the information received from our transfer agent and from brokers and nominees, we estimate the number of beneficial holders of our Units as of February 25, 2005, to be approximately 73,000.
The quarterly cash distributions for the years ended December 31, 2004 and 2003, 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 11. Partner’s Capital and Distributions).
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 paid by us to a unitholder will not result in taxable gain or income except to the extent the aggregate amount distributed exceeds the tax basis of the Units owned by the unitholder.
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 Consolidated 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
The following information is intended to provide investors with an increased understanding of our 2004, 2003 and 2002 consolidated financial statements and our accompanying notes listed in the Index to Consolidated Financial Statements on page of this Report. Our discussion and analysis includes the following:
• Overview of Business and 2004 Results.
• Critical Accounting Policies and Estimates - Presents accounting policies that are among the most critical to the portrayal of our financial condition and results of operations.
• Results of Operations - Discusses material period-to-period variances in the consolidated statements of income.
• Financial Condition and Liquidity - Analyzes cash flows and financial position.
• Other Considerations - Addresses trends, future plans and contingencies that are reasonably likely to materially affect future liquidity or earnings.
Overview of Business and 2004 Results
TEPPCO Partners, L.P., a Delaware limited partnership, is a publicly traded master limited partnership formed in March 1990. See Items 1 and 2. Business and Properties - General. We operate and report in three business segments. Our Downstream Segment owns, operates or has investments in properties located in 14 states, transports, stores and provides terminal services for petroleum products, transports LPGs in the Mont Belvieu area, transports petrochemicals in southeast Texas and provides other ancillary services. Our Upstream Segment gathers, transports, markets and stores crude oil and distributes lubrication oils and specialty chemicals in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Our Midstream Segment gathers natural gas in the Green River Basin in southwestern Wyoming and in the San Juan Basin in northwestern New Mexico and southwestern Colorado, transports NGLs from southeastern New Mexico, East Texas and West Texas to Mont Belvieu, Texas, and fractionates NGLs at two facilities in Colorado. We earn revenues and income and generate cash by charging our customers a fee for the transportation, storage, gathering, terminaling, fractionation and other services we provide. In our Upstream Segment, we seek to maintain a balanced marketing position until we make physical delivery of the crude oil, thereby minimizing or eliminating our exposure to price fluctuations occurring after the initial purchase.
We are subject to economic and other factors that affect our industry. The demand for refined products is dependent upon the price, prevailing economic conditions and demographic changes in the markets served, trucking and railroad freight, agricultural usage and military usage; the demand for propane is sensitive to the weather and prevailing economic conditions; the demand for petrochemicals is dependent upon prices for products produced from petrochemicals; the demand for crude oil and petroleum products is dependent upon the price of crude oil and the products produced from the refining of crude oil; and the demand for natural gas is dependent upon the price of natural gas and the locations in which natural gas is drilled. We are also subject to regulatory factors such as the amounts we are allowed to charge our customers for the services we provide on our regulated pipeline systems.
Certain factors are inherent in our business segments as discussed in this Report. These include the safe, reliable and efficient operation of the pipelines and facilities that we own or operate while meeting increased regulations that govern the operation of our assets and the costs associated with such regulations. We are also focused on our continued growth through expansion of the assets that we own and through the acquisition of assets that complement our current operations.
Our 2004 results illustrate the strength and diversity of our asset portfolio. In 2004, solid operating performance across all of our business segments contributed to a strong year for volumes, net income and earnings before interest, taxes, depreciation and amortization. Our net income for the year ended December 31, 2004, was $142.3 million, compared with $125.8 million for the year ended December 31, 2003. We raised our annual distribution to our unitholders by $0.05 per Unit to an annualized rate of $2.65 per Unit at year end, continuing our twelve year track record of distribution increases. Distributions have increased approximately 35% over the past five years.
Our Downstream Segment had increased revenues from our refined products business and the recognition of $4.1 million of deferred revenue, despite the impact of challenging market conditions for both our refined products and LPGs movements. We have continued to utilize Centennial’s capacity in a manner that has provided additional delivery capability for our customers. Centennial has provided additional capacity through our lease agreement, enabling us to transport additional refined product volumes in 2004. During the third quarter of 2004, Centennial was able to transport jet fuel for the first time. MB Storage also continued its solid performance, in part due to storage and pipeline assets acquired in April 2004. These increases were partially offset by higher pipeline integrity expenses of $6.2 million and an asset impairment charge of $4.4 million related to a marine facility in Beaumont, Texas.
Our Upstream Segment had a strong year, with increased transportation volumes and strong margins in our gathering and marketing business. Transportation volumes on our South Texas system were higher than the prior year, primarily as a result of our November 2003 acquisition of the Genesis assets. We also had a record year for gallons delivered by LSI as a result of acquisitions of lubrication oil distributors in December 2003 and August 2004. These increases were partially offset by increased pipeline integrity expenses of $3.9 million. Seaway had an outstanding year as well, with significant increases in long-haul movements of crude oil.
Our Midstream Segment benefited from increased volumes on Jonah, resulting from our recent Phase III expansion, partially offset by the impact of reduced volumes on Val Verde primarily due to the natural decline of CBM production and slower than anticipated completion and connection of new wells. Our Midstream Segment was impacted by higher operating fuel and power costs, which increased $2.2 million from 2003 primarily due to higher variable power rates and increased NGL volumes transported during times of peak power rates.
We ended 2004 in a solid financial position. Our operating costs overall were higher than expected, largely as a result of pipeline integrity expenses in our Downstream and Upstream Segments. The goal of our on-going pipeline integrity program is to maintain the long-term reliability and safety of our pipeline systems, while minimizing the impact to our customers. Our operating costs were also impacted by increased consulting and contract services of $3.2 million related to compliance with the Sarbanes-Oxley Act of 2002. During the year, we spent $104.4 million on revenue generating capital projects, which we believe will provide earnings, cash flow and growth opportunities. We amended our revolving credit facility in October 2004 to (i) increase the facility size from $550.0 million to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing.
We continued building a base for long-term growth by enhancing existing systems and pursuing new business opportunities. We increased throughput on our pipeline systems, constructed new pipeline and gathering systems, and expanded and upgraded our existing infrastructure. Among the highlights of 2004:
• During the fourth quarter of 2004, we completed a Phase II project to further extend beyond Coshocton, Ohio, our delivery capacity of LPGs to the Northeast by 8,000 to 10,000 barrels per day. The Phase II expansion included the construction of three pump stations between Coshocton and Greensburg, Pennsylvania, and two stations from Greensburg to Watkins Glen, New York. Additional work on the
pipeline segment between Greensburg and Philadelphia, Pennsylvania, to increase delivery rates to the Philadelphia area has been completed. Improvements were also completed during the fourth quarter of 2004 at our Dubois, Pennsylvania, terminal, and additional improvements are expected to be completed during the first quarter of 2005 at our Eagle, Pennsylvania, terminal.
• MB Storage acquired salt dome storage and LPGs pipeline assets in Mont Belvieu, Texas, that will enable future expansion and provide a broader platform for growth.
• We are in the process of constructing a new refined products truck loading terminal in Bossier City, Louisiana, to provide the Shreveport, Louisiana, and East Texas markets with access to Gulf Coast sourced gasoline and diesel fuel. This terminal is scheduled to be completed in the first quarter of 2005.
• We began an expansion project to increase delivery capacity of gasoline and diesel fuel to the Indianapolis, Indiana, and Chicago, Illinois market areas.
• We are in the process of integrating a strategic 58-mile pipeline segment from Houston, Texas, to Katy, Texas, to facilitate Seaway’s connectivity to Gulf of Mexico production and our South Texas system.
• In 2004, we completed the integration of the Genesis assets into our South Texas system. The $21.0 million acquisition has strengthened our existing South Texas market position and improved our physical asset base.
• The Basin system, which is a part of our Upstream Segment, was expanded between Midland, Texas, and Wichita Falls, Texas, resulting in an additional capacity of ten thousand barrels per day on the system.
• Additional capacity of 100 MMcf/day by installing compression facilities on the Jonah system was completed at a cost of approximately $13.0 million. The additional capacity will enable lower operating pressures in the Jonah and Pinedale fields, allowing for improved service and increased throughput.
• We connected Val Verde to two new sources of natural gas production in southern Colorado and northwest New Mexico. Both connections will increase the utilization of the Val Verde assets by up to 150 MMcf/day.
• We inspected more than 2,000 miles of pipeline and completed rehabilitation and enhancement work on an additional 2,000 miles of pipeline as part of our integrity management program.
We remain confident that our current strategy and focus will provide continued growth in earnings and cash distributions. With respect to 2005, these opportunities include:
• Continued solid performance in our Upstream Segment, as we build on our existing asset base and concentrate on acquisitions in our core operating areas;
• Continued development of the Jonah system which serves the Jonah and Pinedale fields;
• Gathering of volumes from infill drilling of CBM by producers and new connections of conventional gas in the San Juan Basin, where our Val Verde system is located;
• Growth in our Downstream Segment, resulting from our recent capacity expansion and grass roots facility investments and growing demand for Gulf Coast sourced products.
Consistent with our business strategy, we continuously evaluate possible acquisitions of assets that would complement our current operations. Such acquisition efforts involve participation by us in processes that have been made public and involve a number of potential buyers, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial position, results of operations or cash flows.
General
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, transportation of NGLs and fractionation 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.
Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, 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 the results of operations of the northern portion of the Dean Pipeline, which transports RGP from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6. Equity Investments).
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, New Mexico 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 transportation logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes our equity investment in Seaway (see Note 6. Equity Investments). Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas.
Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde. DEFS manages and operates the Val Verde, Jonah and Chaparral assets for us under contractual agreements. The results of operations of the acquisitions are included in our consolidated financial statements in periods subsequent to their respective acquisition dates (see Note 5. Acquisitions and Dispositions).
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Although we believe that these estimates are reasonable, actual results could differ from these estimates. Significant accounting policies that we employ are presented in the notes to the consolidated financial statements (see Note 2. Summary of Significant Accounting Policies).
Critical accounting policies are those that are most important to the portrayal of 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 and goodwill and intangible assets.
Revenue and Expense Accruals
We routinely make accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party information and reconciling 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. Most of the estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.
The most difficult accruals to estimate are power costs, property taxes and crude oil margins. Power cost accruals generally involve a two to three month estimate, and the amount varies primarily for actual power usage. Power costs are dependent upon the actual volumes transported through our pipeline systems and the various power rates charged by numerous power companies along the pipeline system. Peak demand rates, which are difficult to predict, drive the variability of the power costs. For the year ended December 31, 2004, approximately 11% of our power costs are recorded using estimates. A variance of 10% in our aggregate estimate for power costs would have an approximate $0.5 million impact on annual earnings. Property tax accruals involve significant tax rate estimates among numerous jurisdictions. Actual property taxes are often not known until the tax bill is settled in subsequent periods, and the tax amount can vary for tax rate changes and changes in tax methods or elections. A variance of 10% in our aggregate estimate for property taxes could have up to an approximate $1.2 million impact on annual earnings. Crude oil margin estimates are based upon an average of the past twelve months of crude oil marketing volumes, factoring in current market events, and prices of crude oil. We use an average of prices that were in effect during the applicable month to determine the expected revenue amount, and we determine the margin by evaluating the actual margins of the prior twelve months. As of December 31, 2004, approximately 10% of our annual crude oil margin is recorded using estimates. A variance from this estimate of 10% would impact the respective line items by approximately $1.0 million on an annual basis. Although the resolution of these uncertainties has not historically had a material impact on our reported results of operations or financial condition, because of the high volume, low margin nature of our business, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Variances from estimates are reflected in the period actual results become known, typically in the month following the estimate. Each of these accruals requires management’s subjective judgments, requiring estimates regarding the effects of items that are inherently uncertain.
Environmental Costs
At December 31, 2004, we have accrued a liability of $5.0 million for our estimate of the future payments we expect to pay for environmental costs to remediate existing conditions attributable to 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 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 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. A variance of 10% in our aggregate estimate for environmental costs would have an approximate $0.5 million impact on annual earnings. For information concerning environmental regulation and environmental costs and contingencies, see Items 1 and 2. Business and Properties - Environmental Matters.
Property, Plant and Equipment
We regularly review long-lived assets for impairment in accordance with Statement of Financial Accounting Standards (“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.
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 intangible assets that have indefinite lives 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 (see Note 3. Goodwill and Other Intangible Assets). At December 31, 2004, the recorded value of goodwill and equity method goodwill was $16.9 million and $25.5 million, respectively. In addition, we have $33.4 million of excess investment in our equity investment in Centennial, which is being accounted for as an intangible asset with an indefinite life.
At December 31, 2004, we have $371.6 million of intangible assets related to 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 and Dispositions). 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 the acquisition. 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 acquisition. 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 35 years and 30 years, respectively. On a quarterly basis, we update throughput estimates and evaluate the remaining expected useful life of the contract assets based upon the best available information. A variance of 10% in our aggregate production estimate for the Jonah and Val Verde systems would have an approximate $2.3 million impact on annual earnings. 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 information by business segment for the years ended December 31, 2004, 2003 and 2002 (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 provides financial information for the Downstream Segment for the years ended December 31, 2004, 2003 and 2002 (in thousands):
The following table presents volumes delivered in barrels and average tariff per barrel for the years ended December 31, 2004, 2003 and 2002 (in thousands, except tariff information):
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. Demand for distillates is affected by truck and railroad freight, the price of natural gas used by utilities, which use distillates as a substitute for natural gas when the price of natural gas is high, and usage for agricultural operations, which is affected by weather conditions, government policy and crop prices. 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 in the past and will likely continue to occur in the future.
Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
Revenues from refined products transportation increased $9.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003. Refined products transportation revenues increased primarily due to higher market-based tariff rates which went into effect in July 2003 and May 2004 and a shift in the distribution of product moved by us to favor longer haul, higher tariff movements. These changes resulted in a 5% increase in the refined products average rate per barrel from the prior year and offset the effect of a 1% decrease in refined products delivery volumes. In February 2003, we entered into a lease agreement with Centennial that increased our flexibility to deliver refined products to our market areas. Volumes transported on Centennial increased due to increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets. Centennial has provided our system with additional pipeline capacity for products originating in the U.S. Gulf Coast area. Prior to the construction of Centennial, deliveries on our pipeline system were limited by our pipeline capacity, and transportation services for our customers were allocated in accordance with a proration policy. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs.
Refined products transportation revenues also increased due to the recognition of $4.1 million of deferred revenue related to the expiration of two customer transportation agreements. Under some of our transportation agreements with customers, the contracts specify minimum payments for transportation services. If the transportation services paid for are not used, the unused transportation service is recorded as deferred revenue. The contracts generally specify a subsequent period of time in which the customer can transport excess products to recover the amount recorded as deferred revenue. During the third quarter of 2004, the time limit under two transportation agreements expired without the customers recovering the unused transportation services. As a result, we recognized the deferred revenue as refined products revenue in the current period. This additional revenue increased the refined products average tariff for the year ended December 31, 2004, by $0.02 per barrel, or 2%.
Revenues from LPGs transportation decreased $4.7 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to lower deliveries of propane in the upper Midwest and Northeast market areas attributable to warmer weather during the first and fourth quarters of 2004. Additionally, in late February 2004, the Mont Belvieu propane price spiked, which resulted in TEPPCO sourced propane being less competitive than propane from other source points. Also contributing to the decrease were less favorable price differentials between Mont Belvieu and other supply centers during the second and third quarters of 2004. High propane prices in 2004 also reduced the summer and early fall fill of consumer storage of propane during 2004. These decreases were partially offset by increased deliveries of isobutane to Chicago area refineries and increased short-haul propane deliveries to U.S. Gulf Coast petrochemical customers. The LPGs average rate per barrel decreased 8% from the prior year period primarily as a result of increased short-haul deliveries during 2004.
Other operating revenues increased $8.5 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to higher propane inventory fees, higher margins on product inventory sales, higher revenue from our Providence, Rhode Island import facility and higher refined products tender deduction, loading and custody transfer revenues.
Costs and expenses increased $25.4 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to increased operating, general and administrative expenses, increased depreciation and amortization expense and increased operating fuel and power, partially offset by net gains on the sales of assets. Operating, general and administrative expenses increased primarily due to a $6.2 million increase in pipeline inspection and repair costs associated with our integrity management program, a $2.0 million increase in legal accruals related to the settlement of a lawsuit (see Note 16. Commitments and Contingencies), a $1.5 million increase in rental expense from the Centennial pipeline capacity lease agreement that we entered into in February 2003, a $1.3 million increase in consulting and contract services related to compliance with the Sarbanes-Oxley Act of 2002 and a $1.1 million increase in costs related to unsuccessful acquisition evaluations. These increases were partially offset by $0.8 million of lower expenses in the 2004 period associated with the write-off of receivables related to customer bankruptcies and non-payments in 2003. Depreciation expense increased from the prior year period because of a $4.4 million charge resulting from the impairment of marine assets in the Beaumont area (see Note 9. Property, Plant and Equipment). In addition, we wrote off approximately $2.1 million in assets taken out of service during the period to depreciation expense. Depreciation expense also increased approximately $5.0 million as a result of assets placed in service during 2003 and 2004, partially offset by an increase in the estimated remaining life of a section of our pipeline system in the Northeast, resulting from pipeline capital improvements made as part of our integrity management program. Operating fuel and power expense increased primarily as a result of higher power rates during the 2004 period. In addition, we recognized net gains of $0.5 million during 2004 from the sales of various assets in the Downstream Segment.
Net losses from equity investments decreased $0.7 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, as shown below (in thousands):
Equity losses in Centennial for the year ended December 31, 2004, compared with the year ended December 31, 2003, decreased $0.1 million, primarily due to increased transportation revenues and volumes and lower operating expenses. During 2003, we acquired an additional 16.7% interest in Centennial on February 10, 2003, bringing TE Products’ ownership interest to 50%. Included in the equity loss for the year ended December 31, 2004, is $1.2 million of equity income relating to the settlement of certain transmix matters recognized in previous periods.
Equity earnings from our 50% ownership interest in MB Storage increased $0.5 million for the year ended December 31, 2004, compared with the year ended December 31, 2003. In April 2004, MB Storage acquired storage and pipeline assets and contracts for approximately $34.0 million, of which TE Products contributed $16.5 million. The increase in equity earnings is due to increased storage revenue, shuttle revenue and rental revenue primarily from the acquired contracts and lower pipeline rehabilitation expenses on the MB Storage system, partially offset by increased amortization and depreciation expense on storage assets and contracts acquired.
Other income - net increased $0.6 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to higher interest income earned on cash investments and higher interest income earned on a capital lease.
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
Revenues from refined products transportation increased $15.5 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to an overall increase of 12% in the refined products volumes delivered. This increase in volumes delivered was primarily due to deliveries of products received into our pipeline from Centennial at Creal Springs, Illinois. Centennial, which began operations in April 2002, has provided our system with additional pipeline capacity for products originating in the U.S. Gulf Coast area. In February 2003, we entered into a lease agreement with Centennial that increased our capacity to deliver refined products to our market areas. Prior to the lease agreement with Centennial, deliveries on our pipeline system were based upon a proration policy, which limited customer transportation. During 2003, with the expanded capacity through our lease agreement with Centennial, our pipeline system was not prorated during portions of 2003 and was better able to serve markets which increased transportation on our system. In addition, in December 2002, we raised the operating pressure of our Chicago lateral pipeline, which resulted in an increase in capacity for deliveries into the Indianapolis and Chicago markets. With this incremental pipeline capacity, our previously constrained system has expanded deliveries in markets both south and north of Creal Springs. Volume increases were due to increased demand and market share for products supplied from the U.S. Gulf Coast into Midwest markets. The refined products average rate per barrel increased 1% from the prior year period primarily due to higher market-based tariff rates which went into effect in July 2003, partially offset by the impact of the Midwest origin point for barrels received from Centennial, which resulted in an increase in short-haul barrels transported on our system.
Revenues from LPGs transportation increased $17.2 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to increased deliveries of propane in the upper Midwest and Northeast market areas attributable to colder than normal weather during the first quarter of 2003 and due to low inventories at competing supply locations during the second and third quarters of 2003. The U.S. Gulf Coast had higher propane inventory during 2003 as compared to the previous year because of higher than normal foreign propane imports at Mont Belvieu, which resulted in a lower propane price in this market area. This lower price contributed to increased transportation deliveries to the mid-continent market areas. Additional pipeline capacity for expanded propane movements was available due to a shift of refined product volumes to Centennial. Butane deliveries also increased due to the increased demand by refineries for normal butane for use in gasoline blending and increased isobutane deliveries to Chicago area refineries. The LPGs average rate per barrel increased 17% from the prior year period as a result of an increased percentage of long-haul deliveries during the year ended December 31, 2003, and an increase in LPG tariff rates, which went into effect in July 2003.
Effective January 1, 2003, TE Products’ 50% ownership interest in MB Storage is accounted for as an equity investment as a result of the formation of MB Storage. Revenues and expenses related to Mont Belvieu operations are now recorded within equity earnings. See discussion regarding changes in equity earnings/losses below.
Other operating revenues increased $5.4 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to the addition of the northern portion of the Dean Pipeline to the Downstream Segment in January 2003, which increased other operating revenues by $4.5 million as the pipeline began transporting RGP in January 2003. The increase was also due to higher propane deliveries at our Providence, Rhode Island import facility and higher refined product loading fees. These increases were partially offset by lower revenues from product location exchanges which are used to position product in the Midwest market area and lower volume of product inventory sales.
Costs and expenses increased $22.3 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to increased operating, general and administrative expenses and increased depreciation and amortization expense, partially offset by decreased taxes - other than income taxes and decreased operating fuel and power. Operating, general and administrative expenses increased primarily due to higher pipeline maintenance expenses, due in part to pipeline rehabilitation expenses associated with our integrity management program, increased consulting and contract services, increased labor costs primarily due to an increase in the number of employees between years, increased insurance expense, expense from the Centennial pipeline capacity lease agreement that we entered into in 2003 and the write-off of receivables of $0.8 million related to customer bankruptcies or other customer non-payments. The addition of the northern portion of the Dean Pipeline to the Downstream Segment increased operating, general and administrative expense by $0.7 million. Depreciation expense increased from the prior year period because of assets placed in service during the year. In addition, we wrote off assets taken out of service during the period to depreciation expense, which also increased depreciation expense. These increases in depreciation expense were partially offset by lower depreciation expense from assets retired during the year, which reduced the asset base, and due to the transfer of assets to MB Storage. Taxes - other than income taxes decreased as a result of actual property taxes being lower than previously estimated and due to the transfer of assets to MB Storage. Operating fuel and power expense decreased as a result of lower power costs due to a slight decrease in the price of natural gas, partially offset by increased mainline throughput.
Net losses from equity investments decreased $2.7 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, as shown below (in thousands):
Equity losses in Centennial for the year ended December 31, 2003, increased $4.7 million compared with the year ended December 31, 2002, due to higher operating expenses primarily as a result of a full year of operating costs in 2004, partially offset by higher transportation volumes and revenues. Centennial commenced operations in April 2002. On February 10, 2003, TE Products acquired an additional 16.7% interest in Centennial, bringing its ownership interest to 50%. In April 2003, TE Products entered into a pipeline capacity lease with Centennial for a period of five years in order to expand its capacity to deliver refined products to its market areas.
Equity earnings from our 50% ownership interest in MB Storage was $7.4 million for the year ended December 31, 2003. Amounts in the prior year period related to Mont Belvieu operations, which were recorded to revenues and costs and expenses are now being recorded within equity earnings based upon our 50% ownership interest in MB Storage, effective with its formation on January 1, 2003. If the 2002 revenues and costs and expenses from the Mont Belvieu operations had been accounted for under the same method as in 2003, equity earnings from MB Storage would have increased $0.2 million in 2003, compared with the prior year, due to increased shuttle deliveries and increased storage revenue, partially offset by increases in depreciation expense and rehabilitation expenses on MB Storage assets.
Other income - net decreased $0.6 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to lower interest income earned on cash investments.
Upstream Segment
The following table provides financial information for the Upstream Segment for the years ended December 31, 2004, 2003 and 2002 (in thousands):
Information presented in the following table includes the margin of the Upstream Segment, which may be viewed as a non-GAAP (Generally Accepted Accounting Principles) financial measure under the rules of the SEC. 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. We believe that margin is a more meaningful measure of financial performance than sales and purchases of crude oil and lubrication oil due to the significant fluctuations in sales and purchases caused by variations in the level of volumes marketed and prices for products marketed. Additionally, we use margin internally to evaluate the financial performance of the Upstream Segment as we believe margin is a better indicator of performance than operating income as operating, general and administrative expenses, operating fuel and power and depreciation expense are not directly related to the margin activities. Margin and volume information for the years ended December 31, 2004, 2003 and 2002 is presented below (in thousands, except per barrel and per gallon amounts):
(1) Margins in this table are presented prior to the elimination of intercompany sales, revenues and purchases between TCO and TCPL.
The following table reconciles the Upstream Segment margin to operating income in the consolidated statements of income using the information presented in the tables above, in the consolidated statements of income and in the statements of income in Note 17. Segment Information (in thousands):
Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
Our margin increased $11.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003. Crude oil transportation margin increased $9.6 million primarily due to an increase in transportation volumes and revenues on our South Texas system and our Red River system. Our Basin system also had increased transportation volumes and revenues primarily due to the expansion of the system between Midland, Texas, and Wichita Falls, Texas, resulting in an additional capacity of ten thousand barrels per day on the system, and movements of barrels on higher tariff segments. During the fourth quarter of 2003, we completed the purchase of crude supply and transportation assets (Genesis), which have been integrated into our South Texas system (see Note 5. Acquisitions and Dispositions). Lubrication oil sales margin increased $1.1 million due to increased sales of chemical volumes and increased volumes related to the acquisitions of lubrication oil distributors in Abilene, Texas, in December 2003 and in Casper, Wyoming, in August 2004. Crude oil marketing margin increased $0.5 million as a result of increased volumes marketed, partially offset by an unfavorable invoicing settlement on a marketing contract in the first quarter of 2003, which reduced the marketing margin in 2003, and increased transportation costs. Crude oil terminaling margin remained unchanged as a result of higher pumpover volumes at Cushing, Oklahoma, offset by lower pumpover volumes at Midland, Texas.
Other operating revenues of the Upstream Segment increased $1.5 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to a $1.4 million favorable settlement of inventory imbalances, and higher 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, increased $5.4 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to increased operating fuel and power, increased depreciation and amortization expense, increased operating, general and administrative expenses and increased taxes - other than income taxes. Operating fuel and power increased $1.8 million primarily as a result of the acquisition of the Genesis assets and higher volumes in 2004. Depreciation and amortization expense increased $1.8 million primarily due to the assets acquired from Genesis. Operating, general and administrative expenses increased $1.0 million from the prior year primarily due to a $3.9 million increase in pipeline inspection and repair costs associated with our integrity management program, a $2.0 million increase in expenses related to the Genesis acquisition, a $1.4 million increase in labor and benefits expense related to incentive compensation plans and an increase in the number of employees between periods, a $0.7 million increase in consulting and contract services related to compliance with the Sarbanes-Oxley Act of 2002 and a $0.6
million increase in rental expense due to our pipeline lease at Freeport, Texas, with Seaway. These increases were partially offset by $3.8 million of higher environmental assessment and remediation costs in 2003, $1.7 million of expense in 2003 from the net settlement of crude oil imbalances with customers, $1.5 million of higher legal costs in 2003 related to the litigation and settlement with D.R.D. Environmental Services, Inc. (“D.R.D.”) and $0.5 million of lower expenses in 2004 from the sale of the Rancho assets in 2003. Taxes - other than income taxes increased $0.8 million due to increases in property tax accruals.
In June 2003, we recorded a net gain of $3.9 million, included in the gain on sale of assets in our consolidated statements of income, on the sale of certain of the assets of the Rancho Pipeline. During the year ended December 31, 2004, we recorded net gains of $0.5 million, included in the gains on sales of assets in our consolidated statements of income, primarily related to the sale of our remaining interest in the original Rancho Pipeline system (see Note 5. Acquisitions and Dispositions).
Equity earnings from our investment in Seaway increased $8.4 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to higher transportation volumes, gains on crude oil inventory sales, a settlement with a former owner of Seaway’s crude oil assets regarding inventory imbalances that were not acquired by us and lower operating, general and administrative expenses.
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
Our margin increased $5.7 million for the year ended December 31, 2003, compared with the year ended December 31, 2002. Crude oil transportation margin increased $6.8 million primarily due to increased revenues on our Red River, Basin, South Texas and West Texas systems resulting from a 15% increase in transportation volumes on these systems partially due to the acquisition of the Genesis assets. During the fourth quarter of 2003, we completed the purchase of crude supply and transportation assets (Genesis), which was integrated into our South Texas system. The acquisition of the Genesis assets increased our transportation and marketing margins by approximately $1.2 million and the barrels transported and marketed by approximately 1.6 million barrels during 2003. Lubrication oil sales margin increased $0.5 million due to increased sales of chemical volumes, higher margins on lubrication sales and increased volumes related to the acquisition of a lubrication oil distributor in Abilene, Texas, in December 2003. Crude oil marketing margin decreased $0.9 million primarily due to an invoicing settlement on a marketing contract in the first quarter of 2003, partially offset by increased volumes marketed, renegotiated supply contracts, lower trucking expenses and more favorable crude oil price differentials. Crude oil terminaling margin decreased $0.7 million as a result of a 10% decrease in volumes at Midland, Texas, and Cushing, Oklahoma.
Costs and expenses, excluding expenses associated with purchases of crude oil and lubrication oil, increased $7.6 million for the year ended December 31, 2003, compared with the year ended December 31, 2002. Operating, general and administrative expenses increased $7.1 million from the prior year period. The increase includes a $2.4 million increase in environmental assessment and remediation costs in 2003, higher legal costs related to the litigation and settlement with D.R.D. and other legal costs (see Note 16. Commitments and Contingencies), $1.7 million of expense from the net settlement of crude oil imbalances with customers, higher pipeline rehabilitation expenses associated with our integrity management program and increased labor costs due to an increase in the number of employees between periods, partially offset by lower general and administrative supplies expenses during the period. In addition, the acquisition of the Genesis assets and integration into our South Texas system during the fourth quarter increased operating, general and administrative expenses by approximately $0.5 million. Operating fuel and power increased $0.3 million due to higher power costs and higher volumes in 2003. Depreciation and amortization expense increased $0.1 million due to assets placed in service in 2002 and 2003 and due to asset retirements. Taxes - other than income taxes increased $0.1 million due to slight increases in property tax accruals.
Equity earnings from our investment in Seaway increased $2.2 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to a favorable crude oil imbalance settlement, a gain on the sale of inventory, lower general and administrative expenses and higher long-haul transportation volumes, partially offset by our portion of equity earnings which decreased from 80% to 60% on a pro-rated basis in 2002 (averaging approximately 67% for the year ended December 31, 2002), to 60% in 2003.
In June 2003, we recorded a net gain of $3.9 million, included in the gain on sale of assets in our consolidated statements of income, on the sale of certain of the assets of the Rancho Pipeline. In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the current owners that previously held undivided interests in the pipeline. We acquired 241 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold 183 miles of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million.
Other income - net decreased $1.2 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to lower interest income received on intercompany borrowings.
Midstream Segment
The following table provides financial information for the Midstream Segment for the years ended December 31, 2004, 2003 and 2002 (in thousands):
The following table presents volume and average rate information for the years ended December 31, 2004, 2003 and 2002 (in thousands, except average fee and average rate amounts):
Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
Revenues from the gathering of natural gas increased $5.0 million for the year ended December 31, 2004, compared with the year ended December 31, 2003. Natural gas gathering revenues from the Jonah system increased $11.3 million and volumes gathered increased 51.6 Bcf for the year ended December 31, 2004, due to the expansion of the Jonah system during 2003. The Phase III expansion was substantially completed during the fourth quarter of 2003 and increased system capacity from 880 MMcf/day to 1,180 MMcf/day. The increase in Jonah’s revenues was also partially due to higher gathering rates realized due to lower system pressures resulting from the increased capacity provided by the Phase III expansion. Natural gas gathering revenues from the Val Verde system decreased $6.3 million and volumes gathered decreased 13.7 Bcf for the year ended December 31, 2004, primarily due to the natural decline of CBM production and slower than anticipated completion and connection of infill wells, partially offset by increased volumes from two new connections made to the Val Verde system in May and December 2004. Val Verde’s average natural gas gathering rate per MMcf decreased due to contracts entered into relating to the new connections, which have lower rates than the existing Val Verde system’s average rates.
Jonah’s Pioneer gas processing plant was completed during the first quarter of 2004, as a part of the Phase III expansion to increase the processing capacity in southwestern Wyoming. Pioneer’s processing agreements allow the producers to elect annually whether to be charged under a fee-based arrangement or a fee plus keep-whole arrangement. Under the fee-based election, Jonah receives a fee for its processing services. Under the fee plus keep-whole election, Jonah receives a lower fee for its processing services, retains and sells the NGLs extracted during the process and delivers to the producers residue gas equivalent in energy to the natural gas received from the producers. Jonah purchases gas from an affiliate of DEFS to replace the equivalent energy removed in the liquids. Jonah sells the NGLs it retains to an affiliate of DEFS. For the year ended December 31, 2004, the sales and purchases under the fee arrangements at the Pioneer plant resulted in a margin (sales of petroleum products less purchases of petroleum products) of $1.4 million.
Revenues from the transportation of NGLs increased $1.4 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to increases in volumes transported on the
Chaparral and Panola Pipelines, partially offset by decreased volumes on the Dean and Wilcox Pipelines. Higher average rates per barrel on volumes transported on the Panola and Wilcox Pipelines were offset by lower average rates per barrel on volumes transported on the Chaparral and Dean Pipelines.
Other operating revenues increased $7.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003. Processing fee revenues increased $2.8 million as a result of Jonah’s Pioneer processing plant, which was constructed as part of the Phase III expansion and placed in service in January 2004. Jonah’s other operating revenues also increased $0.9 million primarily due to higher condensate sales. Other operating revenues on Chaparral increased $1.9 million due to the recognition of deferred revenue related to an inventory settlement. Val Verde’s operating revenues increased $1.6 million due to revenues generated as a result of contractual producer minimum fuel levels exceeding actual operating fuel usage during the year ended December 31, 2004. Val Verde retains a portion of its producers’ gas to compensate for fuel used in operations. The actual usage of gas can differ from the amount contractually retained from producers. Value retained from producers or sales generated as a result of efficient fuel usage is recognized as other operating revenues.
Costs and expenses (excluding purchases of petroleum products) increased $11.7 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to increases in operating, general and administrative expense, operating fuel and power and taxes - other than income taxes, partially offset by a decrease in depreciation and amortization expense. Operating, general and administrative expense increased due to a $3.8 million increase in gas settlement expenses, a $3.0 million increase in general and administrative labor expense, a $1.3 million increase in consulting and contract services related to compliance with the Sarbanes-Oxley Act of 2002, a $0.9 million increase related to our integrity management program and a $0.9 million increase related to Jonah’s processing plant which began operations in 2004. These increases are partially offset by a $0.6 million decrease in expense related to the sale of our Enron Corp. receivable, which had been fully reserved in 2001, and a $0.4 million decrease in maintenance expenditures at Val Verde. Operating fuel and power increased $2.2 million, primarily due to higher variable power rates and increased NGL volumes transported during times of peak variable power rates. Depreciation expense increased $3.5 million, primarily as a result of assets placed in service in 2003 related to the expansion of the Jonah system and additional well connections on the Val Verde system in 2004. Taxes - other than income taxes increased $1.0 million as a result of higher property balances. Amortization expense decreased $4.7 million primarily due to revisions to the estimated life of Jonah’s intangible assets under the units-of-production method, partially offset by a $1.7 million increase as a result of higher volumes in the 2004 period. In second quarter 2003, Jonah’s estimated total throughput of the system was adjusted, which resulted in an extension of the expected amortization period from 16 years to 25 years. During the fourth quarter of 2004, additional limited production forecasts were obtained from some of the producers on the Jonah system related to future expansions of the system, and as a result, we again increased our best estimate of future throughput on the Jonah system. This increase in the estimate of future throughput extended the amortization period of Jonah’s natural gas gathering contracts by an estimated 10 years, increasing from approximately 25 years to approximately 35 years (see Note 3. Goodwill and Other Intangible Assets). Amortization expense on the Val Verde system decreased $2.1 million primarily due to lower volumes in the 2004 period, resulting from the natural decline in CBM production.
Other income - net decreased $0.2 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to lower interest income earned on cash investments.
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
Revenues from the gathering of natural gas increased $45.1 million for the year ended December 31, 2003, compared with the year ended December 31, 2002. Natural gas gathering revenues from the Jonah system increased $14.6 million and volumes gathered increased 54.6 Bcf for the year ended December 31, 2003, due to the expansions of the Jonah system during 2002. The first expansion, which was completed in May 2002, increased the capacity of the Jonah system by 62%, from approximately 450 MMcf/day to approximately 730 MMcf/day. In October 2002, additional expansion projects were completed, which increased the capacity of the Jonah system from 730 MMcf/day to approximately 880 MMcf/day. A Phase III expansion was substantially completed during the fourth quarter of 2003 and increased system capacity to 1,180 MMcf/day. The increase in Jonah’s revenues was also partially due to an increase in the average natural gas gathering rate due to certain volume thresholds being exceeded. Natural gas gathering revenues from the Val Verde system increased $30.5 million and volumes gathered increased 65.9 Bcf for the year ended December 31, 2003, primarily due to the acquisition of the Val Verde system
on June 30, 2002. Volumes delivered for the first half of 2003 were approximately 82.0 Bcf. As Val Verde was acquired on June 30, 2002, there were no comparable volumes for the first half of 2002. Volumes delivered during the second half of 2003 as compared to the second half of 2002 declined approximately 16.0 Bcf. This decrease in volumes during the second half of 2003 was due to the natural decline of CBM production, which resulted in decreased revenues, partially offset by an increase in the average natural gas gathering rate due to annual fee escalations in gathering agreements and higher carbon dioxide treating fees as a result of increasing carbon dioxide content in the natural gas.
Revenues from the transportation of NGLs increased $1.0 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to an increase of $4.4 million related to the acquisition of Chaparral on March 1, 2002, $0.7 million due to an increase in volumes transported on Chaparral and $0.2 million due to an increase in volumes transported on the Wilcox Pipeline. This increase was partially offset by a decrease of $2.4 million due to lower transportation volumes on Panola as a result of lower NGL volumes available from the connected NGL plants and a decrease of $1.9 million on the southern portion of the Dean Pipeline due to decreased transportation volumes. Lower transportation volumes on the southern portion of the Dean Pipeline resulted from the conversion of the northern portion of the pipeline to transport RGP and subsequent classification as a part of the Downstream Segment, effective January 1, 2003. The decrease in the NGL transportation average rate per barrel resulted from a lower average rate per barrel on volumes transported on Chaparral.
Costs and expenses increased $26.6 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to increased depreciation and amortization expense, increased operating, general and administrative expense and increased operating fuel and power, partially offset by decreased taxes - other than income taxes. Depreciation and amortization expense increased $14.6 million due to the Chaparral and Val Verde assets acquired on March 1, 2002, and June 30, 2002, respectively, $0.3 million due to assets placed in service in 2002 related primarily to the expansions of the Jonah system and $2.0 million in amortization expense on Jonah’s intangible assets under the units-of-production method, as volumes gathered increased between periods. These increases were partially offset by a decrease of $1.8 million in amortization expense on Val Verde’s intangible assets under the units-of-production method as volumes gathered decreased between periods. In addition, amortization expense on Jonah decreased $2.0 million related to its intangible assets. In second quarter 2003, Jonah’s estimated total throughput of the system was adjusted, which resulted in an extension of the expected amortization period from 16 years to 25 years (see Note 3. Goodwill and Other Intangible Assets). Operating, general and administrative expense increased $11.0 million from the assets acquired, and $1.1 million primarily due to higher general and administrative labor and supplies expense and increased consulting and contracting services. Operating fuel and power costs increased $0.8 million due to the assets acquired and $0.8 million due to increased volumes transported on Chaparral. Taxes - other than income taxes decreased $0.2 million due to actual property taxes being lower than previously estimated on Val Verde, Panola and the southern portion of the Dean Pipeline.
Interest Expense and Capitalized Interest
Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
Interest expense decreased $13.3 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to a higher percentage of variable interest rate debt during the year ended December 31, 2004, that carried a lower rate of interest as compared to fixed interest rate debt. The higher percentage of variable interest rate debt resulted from the expiration of an interest rate swap in April 2004 (see Note 4. Interest Rate Swaps). The decrease was partially offset by higher balances outstanding on our revolving credit facility in 2004.
Capitalized interest decreased $1.1 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, due to interest capitalized on lower construction work-in-progress balances in 2004.
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
Interest expense increased $19.0 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to $12.3 million of additional expense related to changes in our fair value
and cash flow hedging activities, $16.1 million of additional expense related to the issuance of our 6.125% Senior Notes in January 2003 and our 7.625% Senior Notes in February 2002 and $1.3 million of debt issuance costs written off in June 2003 related to the refinancing of our revolving credit facility. These increases were partially offset by a $10.7 million reduction in interest expense related to decreased borrowings under our revolving credit facility.
Capitalized interest increased $0.9 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, due to increased construction work-in-progress balances during 2003, partially offset by interest capitalized on our investment in Centennial during the first quarter of 2002.
Financial Condition and Liquidity
Cash generated from operations, credit facilities and debt and equity offerings are our primary sources of liquidity. At December 31, 2004, and 2003, we had working capital deficits of $37.8 million and $22.8 million, respectively. At December 31, 2004, we had approximately $132.0 million in available borrowing capacity under our revolving credit facility to cover any working capital needs. Cash flows for the years ended December 31, 2004, 2003 and 2002 were as follows (in millions):
Operating Activities
Net cash from operating activities for the years ended December 31, 2004, 2003 and 2002, was comprised of the following (in millions):
For a discussion of changes in earnings before interest, depreciation and amortization, equity earnings, gain on sales of assets by segment and consolidated interest expense - net, see Results of Operations for the Downstream Segment, Upstream Segment and Midstream Segment in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Cash provided by operating activities increased $26.8 million for the year ended December 31, 2004, compared with the year ended December 31, 2003, primarily due to an increase of $19.2 million in distributions received from our equity investments in Seaway and MB Storage during the year ended December 31, 2004, and higher net income and depreciation and amortization expense in the 2004 period, partially offset by the timing of cash disbursements and cash receipts for working capital components. Cash provided by operating activities increased $4.5 million for the year ended December 31, 2003, compared with the year ended December 31, 2002, primarily due to higher net income and depreciation and amortization expense resulting from our 2002 acquisition of Val Verde, partially offset by the $3.9 million non-cash gain on the sale of assets in 2003. Distributions from equity method investments decreased from 2002 to 2003, primarily due to our sharing ratio in Seaway decreasing from 80% to 60% between years, partially offset by a distribution from MB Storage in 2003 of $5.3 million.
We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and revenue generating expenditures, interest payments on our Senior Notes and revolving credit facility, distributions to our General Partner and unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our General Partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities, and the issuance of additional equity and debt securities. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates and our financial condition and our credit rating at the time.
Net cash from operating activities for the years ended December 31, 2004, 2003 and 2002, included interest payments, net of amounts capitalized, of $77.5 million, $79.9 million and $48.9 million, respectively. Excluding the effects of hedging activities and interest capitalized during the year ended December 31, 2005, we expect interest payments on our fixed rate Senior Notes to be approximately $78.0 million. We expect to pay our interest payments with cash flows from operating activities.
Investing Activities
Cash flows used in investing activities totaled $189.2 million for the year ended December 31, 2004, and were comprised of $164.1 million of capital expenditures, $1.5 million of cash contributions for TE Products’ ownership interest in Centennial, $21.4 million of cash contributions for TE Products’ ownership interest in MB Storage and $3.4 million for the acquisition of assets acquired during the year ended December 31, 2004, partially offset by $1.2 million in net cash proceeds from the sales of various assets in our Upstream and Downstream Segments. Cash flows used in investing activities totaled $185.3 million for the year ended December 31, 2003, and were comprised of $140.6 million of capital expenditures, $22.0 million for our acquisition of the Genesis assets and other assets, $20.0 million for TE Products’ acquisition of an additional 16.7% interest in Centennial, $4.0 million of cash contributions for TE Products’ ownership interest in Centennial and $2.5 million of cash contributions for TE Products’ ownership interest in MB Storage. These uses of cash were partially offset by $3.0 million in net cash proceeds from the Rancho Pipeline transactions and $0.8 million received on matured cash investments. Cash flows used in investing activities totaled $724.7 million for 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 TE Products’ 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.
Financing Activities
Cash flows used in financing activities totaled $90.1 million for the year ended December 31, 2004, and were comprised of $233.1 million of distributions paid to unitholders, partially offset by $143.0 million in borrowings, net of repayments, from our revolving credit facility. Cash flows used in financing activities totaled $55.6 million for the year ended December 31, 2003, and were comprised of $382.0 million in proceeds from revolving credit facilities; $198.6 million from the issuance in January 2003 of our 6.125% Senior Notes due 2013, partially offset by debt issuance costs of $3.4 million; and $287.5 million from the issuance of 9.2 million Units in April and August 2003. These sources of cash for the year ended December 31, 2003, were partially offset by $604.0 million of repayments on our revolving credit facilities, $113.8 million to repurchase and retire all of the 3.9 million outstanding Class B Units, and $202.5 million of distributions paid to unitholders. Cash flows provided by financing activities totaled $495.3 million for the year ended December 31, 2002, and were comprised of $675.0 million in proceeds from 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 Units during the year ended December 31, 2002, and $7.6 million of 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 for the year ended December 31, 2002, were partially offset by $943.7 million of repayments on our revolving credit facilities and $151.8 million of distributions paid to unitholders.
Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2004, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion costs of its pipeline system. TE Products and Marathon have each guaranteed one-half of Centennial’s debt, up to a maximum of $75.0 million each.
Universal Shelf
We have filed with the SEC a universal shelf registration statement that, subject to agreement on terms at the time of use and appropriate supplementation, allows us to issue, in one or more offerings, up to an aggregate of $2.0 billion of equity securities, debt securities or a combination thereof. At December 31, 2004, we have $2.0 billion available under this shelf registration, subject to customary marketing terms and conditions.
Credit Facilities and Interest Rate Swap Agreements
On April 6, 2001, we entered into a $500.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Three Year Facility”). 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 for the Three Year Facility contained certain restrictive financial covenant ratios. During the first quarter of 2003, we repaid $182.0 million of the outstanding balance of the Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under the Three Year Facility with borrowings under a new credit facility, and canceled the Three Year Facility.
On June 27, 2003, we entered into a $550.0 million revolving credit facility with a three year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”). 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 Revolving Credit Facility contains certain restrictive financial covenant ratios. We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. On October 21, 2004, we amended our Revolving Credit Facility to (i) increase the facility size to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing. On December 31, 2004, $353.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 3.0%. At December 31, 2004, we were in compliance with the covenants in this credit agreement.
On January 30, 2003, we completed 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 are being 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 net proceeds received was used for general partnership 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. As of December 31, 2004, we were in compliance with the covenants of these Senior Notes.
We have entered into interest rate swap agreements to hedge our exposure to cash flows and fair value changes. These agreements are more fully described in Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We may be exposed to market risk through changes in crude oil 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.
We seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. On the majority of our crude oil derivative contracts, we take the normal purchase and normal sale exclusion in accordance with 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.
Occasionally, customers require pricing terms which do not allow us to balance our position. Additionally, certain pricing terms may expose us to movements in margin. On a small portion of our crude oil marketing business, we enter into derivative contracts such as physical swaps and other business hedging devices for which we cannot take the normal purchase and normal sale exclusion and for which we do not elect hedge accounting. The terms of these contracts are less than one year. The purpose is to balance our position or lock in a margin and, as such, do not expose us to any additional significant market risk. We mark these transactions to market and the changes in the fair value are recognized in current earnings. This could potentially result in some financial statement variability during quarterly periods; however, any unrealized gains and losses reflected in the financial statements related to marking these transactions to market will be offset by realized gains and losses in different quarterly periods when the related physical transactions are settled.
At December 31, 2004, we had $353.0 million outstanding under our variable interest rate revolving credit facility. 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 our variable interest rate debt outstanding at December 31, 2004, and assuming market interest rates increase 100 basis points, the potential annual increase in interest expense would be $3.5 million.
At December 31, 2004, 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, 2004, the estimated fair value of the TE Products Senior Notes was approximately $412.7 million. At December 31, 2004, we had outstanding $500.0 million principal amount of
7.625% Senior Notes due 2012 and $200.0 million principal amount of 6.125% Senior Notes due 2013. At December 31, 2004, the estimated fair value of the $500.0 million 7.625% Senior Notes and the $200.0 million 6.125% Senior Notes was approximately $569.6 million and $210.2 million, respectively.
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. Interest rate swaps that manage our cash flow risk reduce our exposure to increases in the benchmark interest rates underlying variable rate debt. Interest rate swaps that manage our fair value risks are intended to reduce our exposure to changes in the fair value of the fixed rate debt. 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.
In October 2001, TE Products 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 of interest 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, 2004, 2003 and 2002, we recognized reductions in interest expense of $9.6 million, $10.0 million and $8.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended December 31, 2004, 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 was a gain of approximately $3.4 million at December 31, 2004, and a gain of approximately $2.3 million at December 31, 2003. Utilizing the balance of the 7.51% TE Products Senior Notes outstanding at December 31, 2004, 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.
In July 2000, we 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. This interest rate swap matured in April 2004. We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement was based on a notional amount of $250.0 million. Under the swap agreement, we paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings. In June 2003, we repaid the amounts outstanding under our revolving credit facility with borrowings under a new three year revolving credit facility and canceled the old facility (see Note 10. Debt). We redesignated this interest rate swap as a hedge of our exposure to increases in the benchmark interest rate underlying the new variable rate revolving credit facility. During the years ended December 31, 2004, 2003 and 2002, we recognized increases in interest expense of $2.9 million, $14.4 million and $12.9 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.
During 2003, we determined that we would repay a portion of the amount outstanding under the revolving credit facility with proceeds from our Unit offering in August 2003 (see Note 11. Partners’ Capital and Distributions) resulting in a reduction of probable future interest payments under the credit facility. We reduced the outstanding balance of the revolving credit facility at December 31, 2003, to $210.0 million. During the year ended December 31, 2003, we recognized a loss of $1.0 million for the portion of the discontinued hedge. The total fair value of the interest rate swap was a loss of approximately $3.9 million at December 31, 2003. The remaining $2.9 million of other comprehensive income was transferred to earnings during the period from January 1, 2004, through the maturity of the interest rate swap in April 2004.
In February 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. 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 of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. In July 2002, the swap agreements were terminated
resulting in a gain of approximately $18.0 million. Concurrent with the swap terminations, we entered into new interest rate swap agreements, with identical terms as the previous swap agreements; however, the floating rate of interest was based upon a spread of an additional 50 basis points. In December 2002, the swap agreements entered into in July 2002 were terminated, resulting in a gain of approximately $26.9 million. The gains realized from the July 2002 and December 2002 swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At December 31, 2004, the unamortized balance of the deferred gains was $36.6 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains 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 registered public accounting firm’s 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.
Item 9A.
Item 9A. Controls and Procedures
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-15(e) and 15d-15(e)) as of December 31, 2004, 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.
Management’s Annual Report on Internal Control over Financial Reporting
The management of Texas Eastern Products Pipeline Company, LLC, (the “General Partner”), the General Partner of TEPPCO Partners, L.P. (the “Partnership”), is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Partnership’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Partnership’s internal control over financial reporting includes those policies and procedures that:
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Partnership;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2004. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.
Based on our assessment and those criteria, management believes that the Partnership maintained effective internal control over financial reporting as of December 31, 2004.
The Partnership’s independent auditors have issued an attestation report on management’s assessment of the Partnership’s internal control over financial reporting. That report appears below.
/s/ BARRY R. PEARL
Barry R. Pearl
President and Chief Executive Officer
Texas Eastern Products Pipeline Company, LLC, General Partner
/s/ CHARLES H. LEONARD
Charles H. Leonard
Senior Vice President and Chief Financial Officer
Texas Eastern Products Pipeline Company, LLC, General Partner
Report of Independent Registered Public Accounting Firm
To the Partners of
TEPPCO Partners, L.P.:
We have audited management’s assessment, included in the accompanying report titled Management’s Annual Report on Internal Control over Financial Reporting included in Item 9A, that TEPPCO Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commissions (COSO). TEPPCO Partners, L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of TEPPCO Partners, L.P.’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that TEPPCO Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, TEPPCO Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TEPPCO Partners, L.P. as of December 31, 2004 and 2003, 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, 2004, and our report dated February 24, 2005, expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Houston, Texas
February 24, 2005
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. As a result, no corrective actions were required or undertaken.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Partnership Management
We do not directly have directors or officers, as is commonly the case with publicly traded partnerships. Our operations and activities are managed by the General Partner, which employs our management and operational personnel. The officers and directors of the General Partner are responsible for managing us. 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.
Because we are a limited partnership, we meet the definition of a “controlled company” under the listing standards of the New York Stock Exchange. Accordingly, we and our General Partner are not required to have a majority of independent directors or a nominating or compensation committee of the General Partner’s board of directors.
Committees of the Board of Directors
Audit Committee
Our General Partner has an audit committee (the “Audit Committee”) comprised of three board members who are “independent” as that term is defined in Rule 10A-3 of the Exchange Act and as that term is used in applicable listing standards of the New York Stock Exchange. The members of the Audit Committee are Paul F. Ferguson, Jr. (Chairman), John P. DesBarres and Milton Carroll. 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. No member of the Audit Committee of our General Partner serves on the audit committees of more than three public companies. Our Board of Directors has determined that no Audit Committee member has a material relationship with the Company. Our Board of Directors has also determined that Mr. Ferguson qualifies as an audit committee financial expert as defined in Item 401(h) of Regulation S-K.
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. The Audit Committee has sole authority as to the retention, evaluation, compensation and oversight of the work of the independent auditors. The independent auditors report directly to the Audit Committee. The Audit Committee also has sole authority to approve all audit and non-audit services provided by the independent auditors and shall ensure that the independent auditors are not engaged to perform specific non-audit services prohibited by law or regulation. The charter of the Audit Committee is filed as an exhibit to this Annual Report on Form 10-K and is available on our website at www.teppco.com.
Our Audit Committee has established procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. Persons wishing to communicate with our Audit Committee may do so by calling 1-800-799-4607.
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 P. DesBarres (Chairman), Milton Carroll and Paul F. Ferguson, Jr. 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 Units and debt.
Compensation Committee
The Compensation Committee is a standing committee of the Board of Directors of the General Partner and is composed of five directors, Jim W. Mogg (Chairman), Milton Carroll, Derrill Cody, John P. DesBarres and Paul F. Ferguson, Jr. The Compensation Committee establishes and maintains competitive and equitable compensation and employment policies to retain the management required to carry out our business, to stimulate their useful and profitable efforts on our behalf and to attract necessary additions to management with appropriate qualifications. The Compensation Committee also recommends to the Board of Directors the election of officers and reviews the management succession plans for senior officer positions.
Code of Ethics, Corporate Governance Guidelines and Charter of the Audit Committee
We have adopted a Code of Ethics applicable to all employees, including the principal executive officer, principal financial officer and directors of the General Partner. A copy of the Code of Ethics is available on our
website at www.teppco.com under Corporate Governance. We intend to post on our website any amendments to, or waivers from, our Code of Ethics applicable to our senior officers.
Our Corporate Governance Guidelines address director qualification standards; director access to management, and as necessary and appropriate, independent advisors; director compensation; director orientation and continuing education; management succession and annual performance evaluation of the board. The Charter of our Audit Committee and our Corporate Governance Guidelines are currently available on our website at www.teppco.com under Corporate Governance. Additionally, the Code of Ethics, our Corporate Governance Guidelines and the Charter of the Audit Committee are available in print to any person who requests the information. Persons wishing to obtain this printed material should submit a request in care of Secretary, TEPPCO Partners, L.P., 2929 Allen Parkway, P.O. Box 2521, Houston, Texas 77252-2521.
NYSE Corporate Governance Listing Standards
Annual CEO Certification
As the Chief Executive Officer of Texas Eastern Products Pipeline Company, LLC, as General Partner of TEPPCO Partners, L.P., and as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, I hereby certify that as of the date hereof I am not aware of any violation of the Company of NYSE’s Corporate Governance listing standards, other than has been notified to the Exchange pursuant to Section 303A.12(b) and disclosed as an attachment hereto.
Executive Sessions of Non-Management Directors
Mark A. Borer, Michael J. Bradley, Milton Carroll, Derrill Cody, John P. DesBarres, William H. Easter III, Paul F. Ferguson, Jr. and Jim W. Mogg, who are non-management directors of our General Partner, meet at regularly scheduled executive sessions without management. Mr. Mogg serves as the presiding director at those executive sessions. Persons wishing to communicate with the Company’s non-management directors may do so by calling 1-800-799-4607.
Milton Carroll, John P. DesBarres and Paul F. Ferguson, Jr., who are independent non-management directors of our General Partner, meet at least annually in executive session without management and the other directors. The chairs of the Audit Committee and the Special Committee of the Board of Directors rotate on an annual basis as the chair of the independent non-management directors. The chair for 2005 is Paul F. Ferguson, Jr. Persons wishing to communicate with the Company’s independent non-management directors may do so by calling 1-800-799-4607.
Directors and Executive Officers
The following table sets forth certain information with respect to the directors and executive officers of the General Partner.
* Indicates Chairman of committee
+ Indicates employment contract with the General Partner (see Executive Employment Contracts and Termination of
Employment Arrangements)
Jim W. Mogg 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 was named group vice president and chief development officer of Duke Energy, effective January 1, 2004. He served as chairman, president and chief executive officer of DEFS from December 1999 to December 2003. Mr. Mogg was previously president of Centana Energy Corporation, a subsidiary of a predecessor of Duke Energy, from 1992 to 1999. He joined Duke Energy in 1973 in the gas supply department of Panhandle Eastern Pipe Line Company.
Mark A. Borer was elected a director of the General Partner in April 2000. Mr. Borer is group vice president, marketing and corporate development of DEFS, having been elected to that position in December 2004. He was previously executive vice president of marketing and corporate development of DEFS from April 2002 to December 2004. Mr. Borer previously served as senior vice president, Southern Division, 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 was elected a director of the General Partner in February 2003. Mr. Bradley is group vice president, gathering and processing of DEFS, having been elected to that position in December 2004. He was previously executive vice president, gathering and processing of DEFS, from April 2002 until December 2004. Mr. Bradley 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 was elected a director of the General Partner in November 1997 and is a member of the Compensation Committee, Special Committee and the Audit Committee. 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 chairman of Instrument Products, Inc., a manufacturer of oil field equipment since 1977. Mr. Carroll is a director of Devon Energy Corporation, Eagle Global Logistics and Chairman of the Board of Health Care Service Corporation.
Derrill Cody 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. 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. Mr. Cody is a director of CenterPoint Energy, Inc.
John P. DesBarres 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 H. Easter III was elected a director of the General Partner in February 2004. Mr. Easter is chairman, president and chief executive officer of DEFS, having been elected to that position in January 2004. Mr. Easter joined ConocoPhillips (formerly Conoco Inc.) in 1971 and served in a variety of positions, most recently as general manager of Gulf Coast businesses unit in Lake Charles, Louisiana, from 1998 until 2002 and vice president of state government affairs for ConocoPhillips from 2002 until December 2003.
Paul F. Ferguson, Jr. was elected director of the General Partner in October 2004, and is a member of the Compensation, Audit and Special Committees. He was elected Chairman of the Audit Committee in October 2004. Mr. Ferguson served as senior vice president and treasurer of Duke Energy from June 1997 to June 1998, when he retired. Mr. Ferguson served as senior vice president and chief financial officer of PanEnergy Corp. from September 1995 to June 1997. He held various other financial positions with PanEnergy Corp. from 1988 to 1995, and served as treasurer of Texas Eastern Corporation from 1988 to 1989.
Barry R. Pearl 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 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.
J. Michael Cockrell 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 DETTCO.
Thomas R. Harper 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.
Leonard W. Mallett is Senior Vice President, Operations of the General Partner, having been elected in February 2005. He was previously Vice President, Operations from September 2000 until February 2005. 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.
James C. Ruth is Senior Vice President, General Counsel and Secretary of the General Partner, having been elected in February 2001. Mr. Ruth was previously Vice President and General Counsel and Secretary from 1998 until February 2001, and Vice President, General Counsel from 1991 until 1998. Mr. Ruth joined the Company in 1970.
Barbara A. Carroll 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.
John N. Goodpasture 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 Devon Energy Corporation), 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.
Stephen W. Russell 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.
C. Bruce Shaffer is Vice President, Human Resources and Ethics and Compliance Officer of the General Partner, having been elected in February 2005. Mr. Shaffer joined the Company in August 2004 supporting Human Resources. He was previously Vice President of Human Resources Services for Duke Energy Gas Transmission and Duke Energy Americas from January 2004 until July 2004 and Vice President of Human Resources for Duke Energy North America from June 2003 until July 2004. Mr. Shaffer joined Duke Energy in January 2000 as Managing Director of Human Resources for Duke Energy North America and Duke Energy International.
In addition to our Executive Officers, Mark G. Stockard serves as 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.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires directors, officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of such equity securities. 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, 2004, except for a report covering a transaction that was filed late by Mr. Mallett.
Item 11.
Item 11. Executive Compensation
Summary Compensation Table
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 these persons (see Note 7. Related Party Transactions). The following table reflects cash compensation paid or accrued by the General Partner for the years ended December 31, 2004, 2003 and 2002, with respect to its Chief Executive Officer and the four other most highly compensated executive officers in 2004 (collectively, the “Named Executive Officers”).
SUMMARY COMPENSATION TABLE
(1) Mr. Pearl was elected as Chief Executive Officer and director effective May 1, 2002.
(2) Amounts represent bonuses accrued during the year under the Management Incentive Compensation Plan (“MICP”). Payments under the MICP are made in the subsequent year. Annual compensation does not include awards under long-term incentive plans, which are described in the 2000 LTIP awards table under “Compensation Pursuant to General Partner Plans”.
(3) Amounts represent quarterly distribution equivalents under the terms of the Company’s 2000 Long Term Incentive Plan (“2000 LTIP”) and Phantom Unit Retention Plan (“PURP”).
(4) Amounts represent credits earned to Performance Unit accounts and payouts under the 2000 LTIP.
(5) Includes (i) Company matching contributions under funded, qualified, defined contribution retirement plans; (ii) Company matching contribution credits under unfunded, non qualified plans; (iii) the imputed value of premiums paid by the Company for insurance on the Named Executive Officers’ lives; and (iv) payments received under the Duke Energy Retirement Cash Balance Plan.
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 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 its 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.
Compensation Committee Interlocks and Insider Participation
During 2004, Jim W. Mogg, a director of the General Partner and group vice president and chief development officer of Duke Energy, 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, Derrill Cody, John P. DesBarres and Paul F. Ferguson, Jr., are non-employee directors of the General Partner and are not officers or directors of DEFS or its parent companies, ConocoPhillips or Duke Energy.
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 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 eligible earnings for the plan year less any incentive compensation payments during the plan year, by the Compensation 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 Compensation Committee after the close of a year.
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 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 Unit options awarded. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance
Units may be granted. No awards have been made under the 1994 LTIP since 1999, and none are expected to be made in the future.
There were no Aggregated Option Exercises during the year ended December 31, 2004, under the 1994 LTIP by the Named Executive Officers, and there were no unexercised outstanding Unit options under the 1994 LTIP to the Named Executive Officers as of December 31, 2004.
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 units granted under the award multiplied by (3) the average of the closing prices of a 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 2004 is the three-year period that commenced on January 1, 2004, and ends on December 31, 2006. Each participant’s performance percentage is the result of 100% +/- [(A) minus (C)] divided by [(C) minus (B)] where (A) is the actual Economic Value Added for the performance period, (B) is $67.6 million (which represents the actual Economic Value Added for the three-year period immediately preceding the performance period) and (C) is $103.3 million (which represents the Target Economic Value Added during the three-year performance period). No amounts will be payable under the awards granted in 2004 for the 2000 LTIP unless Economic Value Added for the three year performance period exceeds $67.6 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. For the years ended December 31, 2004 and 2003, EBITDA means, in addition to the above, earnings before other income - net. 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 operating oil supply and the gross value of intangibles and equity investments. Our cost of capital is approved by the Compensation 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 Units equal to the number of phantom 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 2004.
(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 2004 unless Economic Value Added for the three year performance period exceeds $67.6 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 13% increase in Economic Value Added for 2004 as compared with 2003 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. All benefits owed to the Named Executive Officers under the Duke Energy Retirement Cash Balance Plan have been paid. 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 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 ($87,900 for 2004). 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 Executive Cash Balance Plan, the TEPPCO RCBP and the TEPPCO SBP) attributable to such salaries would be as follows: Barry R. Pearl, $73,596; J. Michael Cockrell, $40,571; James C. Ruth, $61,862; Charles H. Leonard, $72,531; and Thomas R. Harper, $15,191. 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 $90,000.
Compensation of Directors
Directors of the General Partner who are neither officers nor employees of either the Company or DEFS receive a stipend, effective January 1, 2005, of $35,000 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, except for attendance of the Audit Committee, for which the amount is $2,000 for each meeting, 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 $8,000 per annum, except for the chairman of the Audit Committee, who receives an additional stipend of $20,000 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 Units.
Effective January 1, 2004, 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 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. Mogg, Pearl, Borer, Bradley and Easter are 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.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Equity Compensation Plan Information
At December 31, 2004, we had no Equity Compensation Plans approved or unapproved by security holders as none of our compensation plans require the issuance of securities or options. During the year ended December 31, 2003, all of the remaining outstanding Unit options under the 1994 LTIP were exercised (see Compensation Pursuant to General Partner Plans). We have no other compensation plans that would result in the issuance of Units.
Security Ownership of Certain Beneficial Owners
As of February 23, 2005, Duke Energy, through its ownership of the Company and other subsidiaries, owns 2,500,000 Units, representing 4.0% of the 63.0 million Units outstanding. No other person is known by us to own more than 5% of our outstanding Units. On February 24, 2005, our General Partner was acquired by EPCO, a privately held company controlled by Dan L. Duncan. Additionally, in a separate transaction, EPCO and its affiliates have agreed to purchase the 2.5 million Units from Duke Energy, valued at approximately $100.0 million (see Note 21. Subsequent Event).
Security Ownership of Management
The following table sets forth certain information, as of February 25, 2005, concerning the beneficial ownership of 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. This information is based on data furnished by the persons named. Based on information furnished to the General Partner by these persons, no director or officer of the General Partner owned beneficially, as of February 25, 2005, more than 1% of the 63.0 million 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.
(3) Units are held jointly with spouse with right of survivorship.
Item 13.
Item 13. Certain Relationships and Related Transactions
Our Management
We have no employees and are managed by the Company, an indirect wholly owned subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 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, 2004, 2003, and 2002, we incurred direct expenses of $83.6 million, $78.0 million and $66.7 million, respectively, which were charged to us by DEFS. Substantially all of these costs were related to payroll and payroll related expenses. For the years ended December 31, 2004, 2003, and 2002, expenses for administrative services and overhead allocated to us by Duke Energy and its affiliates were $1.2 million, $1.1 million and $0.8 million, respectively.
Transactions with DEFS and its affiliates
TCO purchases condensate from DEFS and its affiliates. For the years ended December 31, 2004, 2003, and 2002, TCO’s purchases from DEFS and its affiliates were $141.3 million, $110.7 million and $80.5 million, respectively.
LSI sells lubrication oils and specialty chemicals to DEFS. For the years ended December 31, 2004, 2003, and 2002, revenues recognized by LSI included $16.1 million, $15.2 million and $14.6 million, respectively, for the sale of lubrication oils and specialty chemicals to DEFS.
Effective with the purchase of 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 $7.5 million, $7.4 million and $7.4 million for the years ended December 31, 2004, 2003 and 2002, respectively. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities for TEPPCO Colorado. 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 for each of the years ended December 31, 2004, 2003 and 2002.
The Dean Pipeline and the Wilcox Pipeline were included with the crude oil assets purchased from DEFS effective November 1, 1998. The southern portion of the Dean Pipeline originates in South Texas and transports NGLs for DEFS into its pipeline in Point Comfort, Texas. Revenues recognized from DEFS for NGL transportation totaled $0.2 million, $1.0 million and $2.9 million for the years ended December 31, 2004, 2003 and 2002, respectively. The Wilcox Pipeline, which is located along the Texas Gulf Coast, transports NGLs for DEFS from two of its natural gas processing plants and is currently supported by a throughput agreement with DEFS through November 2005. The fees paid to us by DEFS under the agreement were $1.4 million, $1.5 million and $1.2 million for the years ended December 31, 2004, 2003 and 2002, 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, and transport NGLs for DEFS and other major integrated oil and gas companies. Revenues recognized from an affiliate of DEFS for NGL transportation totaled $11.3 million, $9.2 million and $12.0 million for the years ended December 31, 2004, 2003 and 2002, respectively.
Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence terminal. We operate the terminal and provide propane loading services to an affiliate of DEFS. The agreement was renegotiated in May 2004. During the years ended December 31, 2004, 2003 and 2002, revenues of $4.3 million, $3.2 million and $2.3 million, respectively, from an affiliate of DEFS were recognized pursuant to this agreement.
On September 30, 2001, we purchased Jonah (see Note 5. Acquisitions and Dispositions). 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, 2004, 2003 and 2002, we recognized $4.1 million, $3.7 million and $3.3 million, respectively, of expenses related to the operation and management of the Jonah assets by DEFS. Jonah provides gas gathering services to an affiliate of DEFS. The gathering fees paid to us by an affiliate of DEFS totaled $3.3 million, $2.0 million and $1.2 million for the years ended December 31, 2004, 2003 and 2002, respectively. In connection with Jonah’s Pioneer processing plant operations, which was constructed during the Phase III expansion and began operating in 2004, Jonah sells NGLs to, and purchases gas from, an affiliate of DEFS. For the year ended December 31, 2004, Jonah’s sales to DEFS and its affiliates were $7.1 million, and purchases from DEFS and its affiliates were $5.1 million. In addition, processing fees we received from an affiliate of DEFS for gas processing services at the Pioneer plant totaled $0.6 million for the year ended December 31, 2004.
On March 1, 2002, we purchased the Chaparral NGL system (see Note 5. Acquisitions and Dispositions). 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 years ended December 31, 2004, 2003, and 2002, we recognized
$2.3 million, $2.1 million and $1.7 million, respectively, of expenses related to the operation and management of the Chaparral assets by DEFS. An affiliate of DEFS transports NGLs on the Chaparral NGL system. The fees paid to us by an affiliate of DEFS for NGL transportation on the Chaparral NGL system totaled $3.8 million, $5.5 million and $4.5 million for the years ended December 31, 2004, 2003 and 2002, respectively.
On June 30, 2002, we purchased Val Verde (see Note 5. Acquisitions and Dispositions). 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 years ended December 31, 2004, 2003, and 2002, we recognized $3.8 million, $3.0 million and $1.2 million, respectively, of expenses related to the operation and management of the Val Verde assets by DEFS.
At December 31, 2004 and 2003, we had a receivable from DEFS of $10.5 million and $1.8 million, respectively, related to sales and transportation services provided to DEFS. Included in this receivable balance from DEFS at December 31, 2004, is a gas imbalance receivable of $0.9 million. At December 31, 2004 and 2003, we had a payable to DEFS of $22.4 million and $15.0 million, respectively, related to direct payroll, payroll related costs, management fees, and other operational related charges, including those for Jonah, Chaparral and Val Verde as described above. Included in this payable balance at December 31, 2004 and 2003, is a gas imbalance payable to DEFS of $3.2 million and $1.5 million, respectively.
On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO (see Note 11. Partners’ Capital and Distributions).
We contract with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers insurance coverage. For the years ended December 31, 2004, 2003 and 2002, we incurred insurance expense related to premiums paid to Bison of $6.5 million, $5.9 million and $3.8 million, respectively. At December 31, 2004 and 2003, we had insurance reimbursement receivables due from Bison of $5.2 million and $4.2 million, respectively.
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, 2004, distributions paid to the General Partner totaled $66.9 million, including incentive distributions of $63.5 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 our Units and are treated as Units for purposes of this Report. These 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 these Units with the SEC. As of December 31, 2004, none of these Units had been sold by Duke Energy.
On February 24, 2005, our General Partner was acquired by EPCO, a privately held company controlled by Dan L. Duncan. Additionally, in a separate transaction, EPCO and its affiliates have agreed to purchase the 2.5 million Units from Duke Energy, valued at approximately $100.0 million (see Note 21. Subsequent Event).
Item 14.
Item 14. Principal Accounting Fees and Services
The following table describes fees for professional audit services rendered by KPMG, our principal accountant, for the audit of our financial statements for the years ended December 31, 2004 and 2003, and for fees billed for other services rendered by KPMG during those periods (in thousands):
(1) Audit fees include fees for the audits of the consolidated financial statements as well as for the audit of internal control over financial reporting.
(2) Audit related fees consist principally of fees for audits of financial statements of certain employee benefit plans and certain internal control documentation assistance.
(3) Tax Fees consist of fees for sales and use tax consultation and tax compliance services.
(4) All Other Fees include the aggregate fees we paid during the year ended December 31, 2003, for products and services provided by KPMG, other than the services reported above. The majority of the other fees in 2003 are fees for litigation support services related to the D.R.D. legal proceedings which was settled on July 16, 2003 (see Note 16. Commitments and Contingencies).
Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accountant
Pursuant to its charter, the Audit Committee of our Board of Directors is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent registered public accountants. KPMG’s engagement to conduct our audit was approved by the Audit Committee on April 26, 2004. Additionally, all permissible non-audit engagements with KPMG have been reviewed and approved by the Audit Committee, pursuant to pre-approval policies and procedures established by the Audit Committee.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a) The following documents are filed as a part of this Report:
(1) Financial Statements: See Index to Consolidated Financial Statements on page of this Report for financial statements filed as part of this Report.
(2) Financial Statement Schedules: None.
(3) Exhibits.
Exhibit
Number
Description
3.1
Certificate of Limited Partnership of TEPPCO Partners, L.P. (Filed as Exhibit 3.2 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
3.2
Third Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated September 21, 2001 (Filed as Exhibit 3.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
4.1
Form of Certificate representing Limited Partner Units (Filed as Exhibit 4.1 to the Registration Statement of TEPPCO Partners, L.P. (Commission File No. 33-32203) and incorporated herein by reference).
4.2
Form of Indenture between TE Products Pipeline Company, Limited Partnership and The Bank of New York, as Trustee, dated as of January 27, 1998 (Filed as Exhibit 4.3 to TE Products Pipeline Company, Limited Partnership’s Registration Statement on Form S-3 (Commission File No. 333-38473) and incorporated herein by reference).
4.3
Form of Certificate representing Class B Units (Filed as Exhibit 4.3 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
4.4
Form of Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.2 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.5
First Supplemental Indenture between TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P. and Jonah Gas Gathering Company, as subsidiary guarantors, and First Union National Bank, NA, as trustee, dated as of February 20, 2002 (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of February 20, 2002 and incorporated herein by reference).
4.6
Second Supplemental Indenture, dated as of June 27, 2002, among TEPPCO Partners, L.P., as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., and Jonah Gas Gathering Company, as Initial Subsidiary Guarantors, and Val Verde Gas Gathering Company, L.P., as New Subsidiary Guarantor, and Wachovia Bank, National Association, formerly known as First Union National Bank, as trustee (Filed as Exhibit 4.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
4.7
Third Supplemental Indenture among TEPPCO Partners, L.P. as issuer, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. as Subsidiary Guarantors, and Wachovia Bank, National Association, as trustee, dated as of January 30, 2003 (Filed as Exhibit 4.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.1+
Duke Energy Corporation Executive Savings Plan (Filed as Exhibit 10.7 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.2+
Duke Energy Corporation Executive Cash Balance Plan (Filed as Exhibit 10.8 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.3+
Duke Energy Corporation Retirement Benefit Equalization Plan (Filed as Exhibit 10.9 to Form 10-K for TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1999 and incorporated herein by reference).
10.4+
Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan executed on March 8, 1994 (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1994 and incorporated herein by reference).
10.5+
Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan, Amendment 1, effective January 16, 1995 (Filed as Exhibit 10.12 to Form 10-Q of TEPPCO Partners,
L.P. (Commission File No. 1-10403) for the quarter ended June 30, 1999 and incorporated herein by reference).
10.6+
Form of Employment Agreement between the Company and Thomas R. Harper, Charles H. Leonard, James C. Ruth, John N. Goodpasture, Leonard W. Mallett, Stephen W. Russell, C. Bruce Shaffer, and Barbara A. Carroll (Filed as Exhibit 10.20 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 1998 and incorporated herein by reference).
10.7
Services and Transportation Agreement between TE Products Pipeline Company, Limited Partnership and Fina Oil and Chemical Company, BASF Corporation and BASF Fina Petrochemical Limited Partnership, dated February 9, 1999 (Filed as Exhibit 10.22 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
10.8
Call Option Agreement, dated February 9, 1999 (Filed as Exhibit 10.23 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1999 and incorporated herein by reference).
10.9+
Form of Employment and Non-Compete Agreement between the Company and J. Michael Cockrell effective January 1, 1999 (Filed as Exhibit 10.29 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
10.10+
Texas Eastern Products Pipeline Company Non-employee Directors Unit Accumulation Plan, effective April 1, 1999 (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
10.11+
Texas Eastern Products Pipeline Company Non-employee Directors Deferred Compensation Plan, effective November 1, 1999 (Filed as Exhibit 10.31 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
10.12+
Texas Eastern Products Pipeline Company Phantom Unit Retention Plan, effective August 25, 1999 (Filed as Exhibit 10.32 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 1999 and incorporated herein by reference).
10.13+
Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Amendment and Restatement, effective January 1, 2000 (Filed as Exhibit 10.28 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
10.14+
TEPPCO Supplemental Benefit Plan, effective April 1, 2000 (Filed as Exhibit 10.29 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2000 and incorporated herein by reference).
10.15+
Employment Agreement with Barry R. Pearl (Filed as Exhibit 10.30 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2001 and incorporated herein by reference).
10.16
Second Amended and Restated Agreement of Limited Partnership of TE Products Pipeline Company, Limited Partnership, dated September 21, 2001 (Filed as Exhibit 3.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.17
Amended and Restated Agreement of Limited Partnership of TCTM, L.P., dated September 21, 2001 (Filed as Exhibit 3.9 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.18
Contribution, Assignment and Amendment Agreement among TEPPCO Partners, L.P., TE Products Pipeline Company, Limited Partnership, TCTM, L.P., Texas Eastern Products Pipeline Company, LLC, and TEPPCO GP, Inc., dated July 26, 2001 (Filed as Exhibit 3.6 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2001 and incorporated herein by reference).
10.19
Certificate of Formation of TEPPCO Colorado, LLC (Filed as Exhibit 3.2 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 1998 and incorporated herein by reference).
10.20
Agreement of Limited Partnership of TEPPCO Midstream Companies, L.P., dated September 24, 2001 (Filed as Exhibit 3.10 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2001 and incorporated herein by reference).
10.21
Agreement of Partnership of Jonah Gas Gathering Company dated June 20, 1996 as amended by that certain Assignment of Partnership Interests dated September 28, 2001 (Filed as Exhibit 10.40 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.22
Unanimous Written Consent of the Board of Directors of TEPPCO GP, Inc. dated February 13, 2002 (Filed as Exhibit 10.41 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2001 and incorporated herein by reference).
10.23
Amended and Restated Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and Certain Lenders, as Lenders dated as of March 28, 2002 ($500,000,000 Revolving Facility) (Filed as Exhibit 10.45 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the three months ended March 31, 2002 and incorporated herein by reference).
10.24
Purchase and Sale Agreement between Burlington Resources Gathering Inc. as Seller and TEPPCO Partners, L.P., as Buyer, dated May 24, 2002 (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.25
Amendment, dated as of June 27, 2002 to the Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent, and Certain Lenders, dated as of March 28, 2002 ($500,000,000 Revolving Credit Facility) (Filed as Exhibit 99.3 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of July 2, 2002 and incorporated herein by reference).
10.26
Agreement of Limited Partnership of Val Verde Gas Gathering Company, L.P., dated May 29, 2002 (Filed as Exhibit 10.48 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
10.27+
Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan, effective June 1, 2002 (Filed as Exhibit 10.43 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
10.28+
Amended and Restated TEPPCO Supplemental Benefit Plan, effective November 1, 2002 (Filed as Exhibit 10.44 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.29+
Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan, Second Amendment and Restatement, effective January 1, 2003 (Filed as Exhibit 10.45 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.30+
Amended and Restated Texas Eastern Products Pipeline Company, LLC Management Incentive Compensation Plan, effective January 1, 2003 (Filed as Exhibit 10.46 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.31+
Amended and Restated TEPPCO Retirement Cash Balance Plan, effective January 1, 2002 (Filed as Exhibit 10.47 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.32
Formation Agreement between Panhandle Eastern Pipe Line Company and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, dated as of August 10, 2000 (Filed as Exhibit 10.48 to Form 10-K of TEPPCO Partners, L.P.
(Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.33
Amended and Restated Limited Liability Company Agreement of Centennial Pipeline LLC dated as of August 10, 2000 (Filed as Exhibit 10.49 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.34
Guaranty Agreement, dated as of September 27, 2002, between TE Products Pipeline Company, Limited Partnership and Marathon Ashland Petroleum LLC for Note Agreements of Centennial Pipeline LLC (Filed as Exhibit 10.50 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.35
LLC Membership Interest Purchase Agreement By and Between CMS Panhandle Holdings, LLC, As Seller and Marathon Ashland Petroleum LLC and TE Products Pipeline Company, Limited Partnership, Severally as Buyers, dated February 10, 2003 (Filed as Exhibit 10.51 to Form 10-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the year ended December 31, 2002 and incorporated herein by reference).
10.36
Joint Development Agreement between TE Products Pipeline Company, Limited Partnership and Louis Dreyfus Plastics Corporation dated February 10, 2000 (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2003 and incorporated herein by reference).
10.37
Credit Agreement among TEPPCO Partners, L.P. as Borrower, SunTrust Bank as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders, dated as of June 27, 2003 ($550,000,000 Revolving Facility) (Filed as Exhibit 10.52 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2003 and incorporated herein by reference).
10.38
Agreement of Limited Partnership of Mont Belvieu Storage Partners, L.P. dated effective January 21, 2003 (Filed as Exhibit 10.53 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).
10.39
Letter of Agreement Clarifying Rights and Obligations of the Parties Under the Mont Belvieu Storage Partners, L.P., Partnership Agreement and the Mont Belvieu Venture, LLC, LLC Agreement, dated October 13, 2003 (Filed as Exhibit 10.54 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2003 and incorporated herein by reference).
10.40
Amended and Restated Credit Agreement among TEPPCO Partners, L.P., as Borrower, SunTrust Bank, as Administrative Agent and LC Issuing Bank and The Lenders Party Hereto, as Lenders dated as of October 21, 2004 ($600,000,000 Revolving Facility) (Filed as Exhibit 99.1 to Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) dated as of October 21, 2004 and incorporated herein by reference).
10.41+*
Texas Eastern Products Pipeline Company Amended and Restated Non-employee Directors Deferred Compensation Plan, effective April 1, 2002.
10.42+*
Texas Eastern Products Pipeline Company Second Amended and Restated Non-employee Directors Unit Accumulation Plan, effective January 1, 2004.
12.1*
Statement of Computation of Ratio of Earnings to Fixed Charges.
Subsidiaries of the Partnership (Filed as Exhibit 21 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2002 and incorporated herein by reference).
23*
Consent of KPMG LLP.
24*
Powers of Attorney.
31.1*
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* Filed herewith.
** Furnished herewith pursuant to Item 601(b)-(32) of Regulation S-K.
+ A management contract or compensation plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
By: Texas Eastern Products Pipeline
Company, LLC, as General Partner
Dated: March 1, 2005
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 dates indicated.
* Signed on behalf of the Registrant and each of these persons:
CONSOLIDATED FINANCIAL STATEMENTS
OF TEPPCO PARTNERS, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2004 and 2003
Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002
Consolidated Statements of Partners’ Capital for the years ended December 31, 2004, 2003 and 2002
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2004 and 2003, 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, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of TEPPCO Partners, L.P.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2005, expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
Houston, Texas
February 24, 2005
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 an indirect 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 interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 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, 2004, none of these Limited Partner Units had been sold by Duke Energy.
At December 31, 2004 and 2003, we had outstanding 62,998,554 Limited Partner Units. At December 31, 2002, we had outstanding 3,916,547 Class B Limited Partner Units (“Class B Units”), which were issued to Duke Energy Transport and Trading Company, LLC (“DETTCO”) in connection with an acquisition of assets initially acquired in 1998. On April 2, 2003, we repurchased and retired all of the 3,916,547 previously outstanding Class B Units with proceeds from the issuance of additional Limited Partner Units (see Note 11. Partners’ Capital and Distributions). Collectively, the Limited Partner Units and Class B Units are referred to as “Units.”
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
We adhere to 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. 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. Although we believe these estimates are reasonable, actual results could differ from those estimates.
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.
Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). We refer to refined products, LPGs, petrochemicals, crude oil, NGLs and natural gas 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, 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, New Mexico and the Rocky Mountain region. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas. 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. (“TCO”), 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 earned 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 Segment marketing affiliate. Fractionation revenues are recognized ratably over the contract year as products are delivered to DEFS. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances discussed in “Natural Gas Imbalances.” Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.
Cash and Cash Equivalents
Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximate fair value because of the short term nature of these investments.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2004, 2003 and 2002 (in thousands):
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. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at the lower of fair value or cost.
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. 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.
Asset Retirement Obligations
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. Determination of any amounts 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 an interstate trunk 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 wells owned by 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 fractionator facilities in Colorado.
We have completed our assessment of SFAS 143, and we have determined that we are obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of our assets. However, we are not able to reasonably determine the fair value of the asset retirement obligations for our trunk, interstate and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate.
In order to determine a removal date for our gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of crude oil and natural gas, we are not a producer of the field reserves, and we therefore do not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which we gather crude oil and natural gas. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates of our gathering assets will occur. With regard to our trunk and interstate pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found.
We will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. The adoption of SFAS 143 did not have an effect on our financial position, results of operations or cash flows.
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 5.74%, 6.50% and 5.11% for the years ended December 31, 2004, 2003 and 2002, respectively. During the years ended December 31, 2004, 2003 and 2002, the amount of interest capitalized was $4.2 million, $5.3 million and $4.3 million, respectively.
Intangible Assets
Intangible assets at December 31, 2004, consist primarily of gathering contracts assumed in the acquisition of Jonah Gas Gathering System (“Jonah”) on September 30, 2001, and the acquisition of Val Verde Gathering System (“Val Verde”) on June 30, 2002, the fractionation agreement with DEFS and other intangible assets (see Note 3. Goodwill and Other Intangible Assets).
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 gather coal bed methane (“CBM”) from the San Juan Basin in New Mexico and Colorado, respectively (see Note 5. Acquisitions and Dispositions). The value assigned to these intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production to the gathering system. These intangible assets are 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. Revisions to the unit-of-production estimates may occur as additional production information is made available to us (see Note 3. Goodwill and Other Intangible Assets).
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 (see Note 7. Related Party Transactions).
In connection with the acquisition of crude supply and transportation assets in November 2003, we acquired intangible customer contracts for $8.7 million, which are amortized on a unit-of-production basis (see Note 5. Acquisitions and Dispositions).
We have $33.4 million of excess investment in our equity investment in Centennial Pipeline LLC, which was created upon formation of the company. The excess investment is included in our equity investments account. This excess investment is accounted for as an intangible asset with an indefinite life. We assess the intangible asset for impairment on an annual basis (see Note 3. Goodwill and Other Intangible Assets).
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 FASB in July 2001 (see Note 3. Goodwill and Other Intangible Assets). SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing 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 (equity method goodwill).
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 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 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.
The following table presents the activity of our environmental reserve for the years ended December 31, 2004, 2003 and 2002 (in thousands):
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, Val Verde and 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 they nominated, Val Verde and Jonah record a receivable reflecting the amount due from customers and a payable for the same amount due to connecting pipeline transporters or shippers. We record natural gas imbalances using a mark-to-market approach.
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 and state 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.
Use of Derivatives
We account for derivative financial instruments in accordance with 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.
Our derivative instruments consist primarily of interest rate swaps and contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities. Substantially all derivative instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended, and as such, changes in the fair value of petroleum product purchase and sales agreements are reported on the accrual basis of accounting. SFAS 133 describes normal purchases and sales as contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.
For all hedging relationships, we formally document at inception the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed and a description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as fair value or cash flow to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.
For derivative instruments designated as fair value hedges, gains and losses on the derivative instrument are offset against related results on the hedged item in the statement of income. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. 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. The ineffective portion of the change in fair value of a derivative instrument that qualifies as either a fair value hedge or a cash flow hedge is reported immediately in earnings.
According to SFAS 133, as amended, we are required to discontinue hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.
When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective fair value hedge, we continue to carry the derivative on the balance sheet at its fair value and no longer adjust the hedged asset or liability for changes in fair value. The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or
liability. When hedge accounting is discontinued because the hedged item no longer meets the definition of a firm commitment, we continue to carry the derivative on the balance sheet at its fair value, remove any asset or liability that was recorded pursuant to recognition of the firm commitment from the balance sheet, and recognize any gain or loss in earnings. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, we continue to carry the derivative on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive income are recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, we continue to carry the derivative at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.
Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature. The fair values of these financial instruments are represented in our consolidated balance sheets.
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 Units outstanding (a total of 63.0 million Units, 59.8 million Units and 49.2 million Units for the years ended December 31, 2004, 2003 and 2002, respectively). The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each year (see Note 11. Partner’s Capital and Distributions). The General Partner was allocated $41.1 million (representing 28.85%) of net income for the year ended December 31, 2004, $34.8 million (representing 27.65%) of net income for the year ended December 31, 2003, and $29.7 million (representing 25.18%) of net income for the year ended December 31, 2002. The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our Limited Partnership Agreement.
Diluted net income per Unit is similar to the computation of basic net income per Unit discussed above, except that the denominator is increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the years ended December 31, 2003 and 2002, the denominator was increased by 11,878 Units and 32,053 Units, respectively. For the year ended December 31, 2004, diluted net income per Unit equaled basic net income per Unit as the denominator was not changed because all remaining outstanding Unit options were exercised during the third quarter of 2003 (see Note 13. Unit-Based Compensation).
Unit Option Plan
We have not granted options for any periods presented. For options outstanding under the 1994 Long Term Incentive Plan (see Note 13. 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 Units on the date of the grant. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised.
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 13. Unit-Based Compensation.
Assuming we had used the fair value method of accounting for our Unit option plan, pro forma net income for the year ended December 31, 2002, would be lower than reported net income by an immaterial amount. Pro forma net income would equal reported net income for the years ended December 31, 2004 and 2003. Pro forma net income per Unit would equal reported net income per Unit for the periods presented. The adoption of SFAS 148 did not have an effect on our financial position, results of operations or cash flows.
New Accounting Pronouncements
In December 2003, the FASB revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46”). FIN 46, issued by the FASB in January 2003, 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. The revised statement, FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (“FIN 46(R)”), clarifies some of the requirements of FIN 46, eases some implementation problems that companies experienced implementing FIN 46, adds new scope exceptions and makes the probability more likely for many companies that potential variable interest entities will be identified and consolidated. We adopted the new requirements detailed in FIN 46(R) as of March 31, 2004. In connection with our adoption of FIN 46(R), we evaluated our investments in Centennial Pipeline LLC, Seaway Crude Pipeline Company and Mont Belvieu Storage Partners, L.P. and determined that these entities are not materially affected by our adoption of FIN 46(R), and thus we have accounted for them as equity method investments (see Note 6. Equity Investments). Our adoption of FIN 46(R) did not have an effect on our financial position, results of operations or cash flows.
On December 8, 2003, President Bush signed into law a bill that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. We anticipate that the benefits we pay after 2006 could be lower as a result of the new Medicare provisions; however, at this time the retiree medical obligations and costs reported do not reflect any changes as a result of this legislation. Deferring the recognition of the new Medicare provisions’ impact was permitted by FASB Staff Position (“FSP”) Nos. 106-1 and 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, due to open questions about some of the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information. We adopted the provisions of these FSPs in the quarter ended September 30, 2004. This regulation did not have a material adverse effect on our financial position, results of operations or cash flows.
In December 2003, the FASB issued a revision SFAS No. 132, Employers’ Disclosures about Pensions and Other Post-Retirement Benefits. This revision required that companies provide more details about their plan assets, benefit obligations, cash flows, benefit costs and other relevant information. A description of investment policies and strategies and target allocation percentages, or target ranges, for these asset categories also is required in financial statements. Cash flows will include projections of future benefit payments and an estimate of contributions to be made in the next year to fund pension and other postretirement benefit plans. In addition to expanded annual disclosures, the FASB is requiring companies to report the various elements of pension and other postretirement benefit costs on a quarterly basis. The guidance is effective for fiscal years ending after December 15, 2003, and for quarters beginning after December 15, 2003. We adopted the provisions of the revised SFAS 132 effective December 31, 2003, and certain provisions regarding disclosure of information about estimated future benefit payments in the first quarter of 2004.
In April 2004, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128, to clarify what is meant by a participating security as described in SFAS No. 128, Earnings Per Share. The consensus also provides guidance on applying the two-class method for computing earnings per share. The two-class method is an earnings allocation formula for computing earnings per share and is the required method prescribed by SFAS 128 for companies with participating
securities or more than one class of common stock. The consensus primarily affects companies that issue securities that are entitled to participate in dividends with common shares and would cause affected companies to report lower earnings per share amounts. The consensus is to be applied retroactively for periods beginning after March 31, 2004. The adoption of EITF 03-06 did not have an effect on our financial position, results of operations or cash flows.
In July 2004, the EITF reached consensus in EITF 02-14, Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock, to clarify whether Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock applies to joint ventures with ownership not represented by common stock. APB Opinion No. 18 scopes out investments with ownership not represented by common stock. EITF 02-14 clarifies that joint ventures with ownership represented by in-substance common stock, as defined by EITF 02-14, are subject to the requirements of APB Opinion No. 18. We do not have common stock ownership in our three joint ventures, Centennial Pipeline LLC, Seaway Crude Pipeline Company and Mont Belvieu Storage Partners, L.P. We have assessed the impact of EITF 02-14 on these three joint ventures and have determined that we have in-substance common stock ownership for all of these ventures. However, similar to other companies with ownership structures in joint ventures not represented by common stock, we have historically accounted for these joint ventures under the guidance of APB Opinion No. 18 due to a lack of other authoritative guidance. The consensuses in this EITF should be applied in reporting periods beginning after September 15, 2004. The adoption of EITF 02-14 did not have an effect on our financial position, results of operations or cash flows.
In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment. SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of the compensation cost is to be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards are to be re-measured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) is a revision of SFAS 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123(R) is effective for public companies as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. All public companies that adopted the fair-value-based method of accounting must use the modified prospective transition method and may elect to use the modified retrospective transition method. We do not believe that the adoption of SFAS 123(R) will have a material effect on our financial position, results of operations, or cash flows.
NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS
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 FASB in July 2001. SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually.
To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units. We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit. We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred. There has been no goodwill impairment losses recorded since the adoption of SFAS 142.
At December 31, 2004 and 2003, we have $16.9 million of unamortized goodwill and $25.5 million of excess investment in our equity investment in Seaway Crude Pipeline Company (equity method goodwill). The excess investment is included in our equity investments account at December 31, 2004. The following table presents the carrying amount of goodwill and equity method goodwill at December 31, 2004 and 2003, by business segment (in thousands):
Other Intangible Assets
The following table reflects the components of intangible assets being amortized at December 31, 2004 and 2003 (in thousands):
SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortization expense on intangible assets was $32.2 million, $36.2 million and $27.9 million for the years ended December 31, 2004, 2003 and 2002, respectively.
The value assigned to our intangible assets for natural gas gathering contracts 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. We update throughput estimates and evaluate the remaining expected useful lives of the contract assets on a quarterly basis based on the best available information. Due to expansions on the gathering systems at Jonah and because of certain limited production forecasts obtained from some of the producers on the Jonah system related to the expansions, in the second quarter of 2003 we increased our best estimate of future throughput on the Jonah system. This increase in the estimate of future throughput extended the amortization period of Jonah’s natural gas gathering contracts by an estimated 9 years, increasing from approximately 16 years to approximately 25 years. During the fourth quarter of 2004, additional limited production forecasts were obtained from some of the producers on the Jonah system related to future expansions of the system, and as a result, we again increased our best estimate of future throughput on the Jonah system. This increase in the estimate of future throughput extended the amortization period of Jonah’s natural gas gathering contracts by an estimated 10 years, increasing from approximately 25 years to approximately 35 years. Revisions to these estimates may occur as additional production information is made available to us.
The amortization of the contracts related to the Val Verde assets is also amortized on a unit-of-production basis. During the fourth quarter of 2004, certain limited production forecasts were obtained from some of the producers on the Val Verde system, and as a result, the amortization period of Val Verde’s natural gas gathering contracts was extended by approximately 10 years, from approximately 20 years to approximately 30 years. Revisions to these estimates may occur as additional production information is made available to us.
The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis. Our fractionation agreement with DEFS is being amortized over its contract period of 20 years. The amortization periods for our other intangible assets, which include non-compete and other agreements, range from 3 years to 15 years. In connection with the acquisition of crude supply and transportation assets in November 2003, we acquired intangible customer contracts for $8.7 million, which are being amortized on a unit-of-production basis (see Note 5. Acquisitions and Dispositions).
At December 31, 2004, we have $33.4 million of excess investment in our equity investment in Centennial Pipeline LLC, which was created upon formation of the company. The excess investment is included in our equity investments account at December 31, 2004. This excess investment is accounted for as an intangible asset with an indefinite life. We assess the intangible asset for impairment on an annual basis.
The following table sets forth the estimated amortization expense of intangible assets for the years ending December 31 (in thousands):
NOTE 4. INTEREST RATE SWAPS
In July 2000, we 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. This interest rate swap matured in April 2004. We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement was based on a notional amount of $250.0 million. Under the swap agreement, we paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings. In June 2003, we repaid the amounts outstanding under our revolving credit facility with borrowings under a new three year revolving credit facility and canceled the old facility (see Note 10. Debt). We redesignated this interest rate swap as a hedge of our exposure to increases in the benchmark interest rate underlying the new variable rate revolving credit facility. During the years ended December 31, 2004, 2003 and 2002, we recognized increases in interest expense of $2.9 million, $14.4 million and $12.9 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.
During 2003, we determined that we would repay a portion of the amount outstanding under the revolving credit facility with proceeds from our Unit offering in August 2003 (see Note 11. Partners’ Capital and Distributions) resulting in a reduction of probable future interest payments under the credit facility. We reduced the outstanding balance of the revolving credit facility at December 31, 2003, to $210.0 million. During the year ended December 31, 2003, we recognized a loss of $1.0 million for the portion of the discontinued hedge. The total fair value of the interest rate swap was a loss of approximately $3.9 million at December 31, 2003. The remaining $2.9 million of other comprehensive income was transferred to earnings during the period from January 1, 2004, through the maturity of the interest rate swap in April 2004.
In October 2001, TE Products 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 of interest 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, 2004, 2003 and 2002, we recognized reductions in interest expense of $9.6 million, $10.0 million and $8.6 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the quarter ended December 31, 2004, 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 was a gain of approximately $3.4 million at December 31, 2004, and a gain of approximately $2.3 million at December 31, 2003.
In February 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. 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 of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. In July 2002, the swap agreements were terminated resulting in a gain of approximately $18.0 million. Concurrent with the swap terminations, we entered into new interest rate swap agreements, with identical terms as the previous swap agreements; however, the floating rate of interest was based upon a spread of an additional 50 basis points. In December 2002, the swap agreements entered into in July 2002 were terminated, resulting in a gain of approximately $26.9 million. The gains realized from the July 2002 and December 2002 swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At December 31, 2004, the unamortized balance of the deferred gains was $36.6 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.
NOTE 5. ACQUISITIONS AND DISPOSITIONS
Jonah Gas Gathering Company
On September 30, 2001, we purchased Jonah from Alberta Energy Company for $359.8 million, with an additional payment of $7.3 million made on February 4, 2002, for final purchase adjustments related primarily to construction projects in progress at the time of closing. The acquisition served as our entry into the natural gas gathering industry. We funded the acquisition through a borrowing under a bank credit facility. We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets for gas gathering contracts. We also 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 operations of the acquisition have been included in our consolidated financial statements from September 30, 2001. 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 35 years) (see Note 3. Goodwill and Other Intangible Assets).
Chaparral NGL System
On March 1, 2002, we purchased 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. The Chaparral NGL system extends from West Texas and New Mexico to Mont Belvieu. The pipeline delivers NGLs to fractionators and to our existing storage facilities in Mont Belvieu. We funded the purchase through borrowings under a bank credit facility. We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting. Accordingly, the results of the acquisition have been included in our consolidated financial statements from March 1, 2002. Under a contractual agreement, DEFS manages and operates Chaparral on our behalf.
Val Verde Gas Gathering Company
On June 30, 2002, we purchased 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. The Val Verde system 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. The purchase was primarily funded through borrowings under bank credit facilities. We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets for gas gathering contracts. We accounted for the acquisition of these assets under the purchase method of accounting. Accordingly, the results of the acquisition have been included in our consolidated financial statements from June 30, 2002. Under a contractual agreement, DEFS manages and operates Val Verde on our behalf.
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. The period of amortization is expected to be approximately 30 years from the date of acquisition.
The following table presents our unaudited pro forma results as though the acquisition of Val Verde occurred at the beginning of 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 acquisition, amortization expense 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 acquisition been consummated at the beginning of 2002, or the results which may be attained in the future.
Rancho Pipeline
In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston, Texas. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the owners that previously held undivided interests in the pipeline. We acquired 241 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold 183 miles of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain of $3.9 million on the transactions in the second quarter of 2003. During the third quarter of 2004, we sold our remaining interest in the original Rancho Pipeline system for a net gain of $0.4 million. These gains are included in the gains on sales of assets in our consolidated statements of income.
Genesis Pipeline
On November 1, 2003, we purchased crude supply and transportation assets along the upper Texas Gulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”). The transaction was funded with proceeds from our August 2003 equity offering (see Note 11. Partners’ Capital and Distributions). We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets. The assets acquired included approximately 150 miles of small diameter trunk lines, 26,000 barrels per day of throughput and 12,000 barrels per day of lease marketing and supply business. We have integrated these assets into our South Texas pipeline system, which has allowed us to consolidate gathering and marketing assets in key operating areas in a cost effective manner and will provide future growth opportunities. Accordingly, the results of the acquisition are included in the consolidated financial statements from November 1, 2003.
The following table allocates the estimated fair value of the Genesis assets acquired on November 1, 2003 (in thousands):
NOTE 6. EQUITY INVESTMENTS
Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway Crude Pipeline Company (“Seaway”). The remaining 50% interest is owned by ConocoPhillips. Seaway 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, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of the Seaway partnership. From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway. Thereafter, we will receive 40% of revenue and expense of Seaway. During the years ended December 31, 2004 and 2003, we received distributions from Seaway of $36.9 million and $22.7 million, respectively.
In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former 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 central Illinois. Through February 9, 2003, each 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 from PEPL for $20.0 million each, increasing their ownership percentages in Centennial to 50% each. During the years ended December 31, 2004 and 2003, TE Products invested an additional $1.5 million and $24.0 million, respectively, in Centennial, which is included in the equity investment balance at December 31, 2004. The 2003 amount includes the $20.0 million paid for the acquisition of the additional ownership interest in Centennial. TE Products has not received any distributions from Centennial since its formation.
On January 1, 2003, TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each own a 50% ownership interest in MB Storage. The purpose of MB Storage is 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. MB Storage is a service-oriented, fee-based venture with no commodity trading activity. TE Products operates the facilities for MB Storage. Effective January 1, 2003, TE Products contributed property and equipment with a net book value of $67.1 million to MB Storage. Additionally, as of the contribution date, Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage that TE Products was required to reimburse if the original joint development and marketing agreement was terminated by either party. This deferred liability was also contributed and credited to the capital account of Louis Dreyfus in MB Storage.
TE Products receives the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the operating agreement. Any amount of MB Storage’s annual income before depreciation expense in excess of $7.15 million is allocated evenly between TE Products and Louis Dreyfus. Depreciation expense on assets each originally contributed to MB Storage is allocated between TE Products and Louis Dreyfus based on the net book value of the assets contributed. Depreciation expense on assets constructed or acquired by MB Storage subsequent to formation is allocated evenly between TE Products and Louis Dreyfus. For the years ended December 31, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storage was approximately 69.4% and 70.4%, respectively. For the years ended December 31, 2004 and 2003, excluding the contribution of property and equipment upon formation of the partnership, TE Products has contributed $21.4 million and $2.5 million, respectively, to MB Storage. The 2004 amount includes a contribution of $16.5 million for the acquisition of storage and pipeline assets in April 2004. The remaining contributions have been for capital expenditures in both periods. During the years ended December 31, 2004 and 2003, TE Products received distributions of $10.3 million and $5.3 million, respectively, from MB Storage.
We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway, Centennial and MB Storage for the years ended December 31, 2004 and 2003, is presented below (in thousands):
Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of December 31, 2004, and December 31, 2003, is presented below (in thousands):
NOTE 7. RELATED PARTY TRANSACTIONS
Duke Energy, DEFS and Affiliates
We have no employees and are managed by the Company, an indirect wholly owned subsidiary of DEFS. Duke Energy holds an interest of approximately 70% in DEFS, and ConocoPhillips holds the remaining interest of approximately 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, 2004, 2003, and 2002, we incurred direct expenses of $83.6 million, $78.0 million and $66.7 million, respectively, which were charged to us by DEFS. Substantially all of these costs were related to payroll and payroll related expenses. For the years ended December 31, 2004, 2003, and 2002, expenses for administrative services and overhead allocated to us by Duke Energy and its affiliates were $1.2 million, $1.1 million and $0.8 million, respectively.
TCO purchases condensate from DEFS and its affiliates. For the years ended December 31, 2004, 2003, and 2002, TCO’s purchases from DEFS and its affiliates were $141.3 million, $110.7 million and $80.5 million, respectively.
Lubrication Services, L.P. (“LSI”) sells lubrication oils and specialty chemicals to DEFS. For the years ended December 31, 2004, 2003, and 2002, revenues recognized by LSI included $16.1 million, $15.2 million and $14.6 million, respectively, for the sale of lubrication oils and specialty chemicals to DEFS.
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 $7.5 million, $7.4 million and $7.4 million for the years ended December 31, 2004, 2003 and 2002, respectively. TEPPCO Colorado and DEFS also entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities for TEPPCO Colorado. 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 for each of the years ended December 31, 2004, 2003 and 2002.
The Dean Pipeline and the Wilcox Pipeline were included with the crude oil assets purchased from DEFS effective November 1, 1998. The southern portion of the Dean Pipeline originates in South Texas and transports NGLs for DEFS into its pipeline in Point Comfort, Texas. Revenues recognized from DEFS for NGL transportation totaled $0.2 million, $1.0 million and $2.9 million for the years ended December 31, 2004, 2003 and 2002, respectively. The Wilcox Pipeline, which is located along the Texas Gulf Coast, transports NGLs for DEFS from two of its processing plants and is currently supported by a throughput agreement with DEFS through November 2005. The fees paid to us by DEFS under the agreement were $1.4 million, $1.5 million and $1.2 million for the years ended December 31, 2004, 2003 and 2002, 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, and transport NGLs for DEFS and other major integrated oil and gas companies. Revenues recognized from an affiliate of DEFS for NGL transportation totaled $11.3 million, $9.2 million and $12.0 million for the years ended December 31, 2004, 2003 and 2002, respectively.
Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence terminal. We operate the terminal and provide propane loading services to an affiliate of DEFS. The agreement was renegotiated in May 2004. During the years ended December 31, 2004, 2003 and 2002, revenues of $4.3 million, $3.2 million and $2.3 million, respectively, from an affiliate of DEFS were recognized pursuant to this agreement.
On September 30, 2001, we purchased Jonah (see Note 5. Acquisitions and Dispositions). 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, 2004, 2003 and 2002, we recognized $4.1 million, $3.7 million and $3.3 million, respectively, of expenses related to the operation and management of the Jonah assets by DEFS. Jonah provides gas gathering services to an affiliate of DEFS. The gathering fees paid to us by an affiliate of DEFS totaled $3.3 million, $2.0 million and $1.2 million for the years ended December 31, 2004, 2003 and 2002, respectively. In connection with Jonah’s Pioneer processing plant operations, which was constructed during the Phase III expansion and began operating in 2004, Jonah sells NGLs to, and purchases gas from, an affiliate of DEFS. For the year ended December 31, 2004, Jonah’s sales to DEFS and its affiliates were $7.1 million, and purchases from DEFS and its affiliates were $5.1 million. In addition, processing fees we received from an affiliate of DEFS for gas processing services at the Pioneer plant totaled $0.6 million for the year ended December 31, 2004.
On March 1, 2002, we purchased the Chaparral NGL system (see Note 5. Acquisitions and Dispositions). 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 years ended December 31, 2004, 2003, and 2002, we recognized $2.3 million, $2.1 million and $1.7 million, respectively, of expenses related to the operation and management of the Chaparral assets by DEFS. An affiliate of DEFS transports NGLs on the Chaparral NGL system. The fees paid to us by an affiliate of DEFS for NGL transportation on the Chaparral NGL system totaled $3.8 million, $5.5 million and $4.5 million for the years ended December 31, 2004, 2003 and 2002, respectively.
On June 30, 2002, we purchased Val Verde (see Note 5. Acquisitions and Dispositions). 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 years ended December 31, 2004, 2003 and 2002, we recognized $3.8 million, $3.0 million and $1.2 million, respectively, of expenses related to the operation and management of the Val Verde assets by DEFS.
At December 31, 2004 and 2003, we had a receivable from DEFS of $10.5 million and $1.8 million, respectively, related to sales and transportation services provided to DEFS. Included in this receivable balance from DEFS at December 31, 2004, is a gas imbalance receivable of $0.9 million. At December 31, 2004 and 2003, we
had a payable to DEFS of $22.4 million and $15.0 million, respectively, related to direct payroll, payroll related costs, management fees, and other operational related charges, including those for Jonah, Chaparral and Val Verde as described above. Included in this payable balance at December 31, 2004 and 2003, is a gas imbalance payable to DEFS of $3.2 million and $1.5 million, respectively.
On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO (see Note 11. Partners’ Capital and Distributions).
We contract with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers insurance coverage. For the years ended December 31, 2004, 2003 and 2002, we incurred insurance expense related to premiums paid to Bison of $6.5 million, $5.9 million and $3.8 million, respectively. At December 31, 2004 and 2003, we had insurance reimbursement receivables due from Bison of $5.2 million and $4.2 million, respectively.
At December 31, 2003, we had a loan of propane outstanding to DEFS with a total value of $1.4 million. We earned a nominal rental fee of $0.1 million on this transaction. This propane was returned to us in February 2004. We regularly loan inventory for a fee to third parties and affiliates as part of our inventory management practice.
Seaway
We own a 50% ownership interest in Seaway, and the remaining 50% interest is owned by ConocoPhillips (see Note 6. Equity Investments). We are the operator of Seaway. During the years ended December 31, 2004, 2003 and 2002, we billed Seaway $7.6 million, $7.4 million and $7.1 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, for each of the years ended December 31, 2004, 2003 and 2002, we billed Seaway $2.1 million for indirect management fees for operating Seaway. At December 31, 2004 and 2003, we had a payable balance to Seaway of $0.5 million and $4.0 million, respectively, for advances Seaway paid to us as operator for operating costs, including payroll and related expenses and management fees.
Centennial
In August 2000, TE Products entered into agreements with PEPL and Marathon to form Centennial (see Note 6. Equity Investments). At December 31, 2004, TE Products had a 50% ownership interest in Centennial. TE Products has entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs, Illinois, and pipeline connection in Beaumont, Texas. For each of the years ended December 31, 2004, 2003 and 2002, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $6.9 million, $4.4 million and $4.0 million, respectively.
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, 2004 and 2003, we had payable balances of $2.8 million and $2.3 million, respectively, to Centennial for its share of the joint tariff deliveries and other operational related charges. 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, 2004 and 2003, TE Products had receivable balances of $1.1 million and $1.3 million, respectively, due from Centennial for reimbursement of construction services provided to Centennial.
In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. For the years ended December 31, 2004 and 2003, TE Products incurred $5.3 million and $3.8 million, respectively, of rental charges related to the lease of pipeline capacity on Centennial.
MB Storage
Effective January 1, 2003, TE Products entered into agreements with Louis Dreyfus to form MB Storage (see Note 6. Equity Investments). TE Products operates the facilities for MB Storage. TE Products and MB Storage have entered into a pipeline capacity lease agreement, and for each of the years ended December 31, 2004 and 2003, TE Products recognized $0.1 million in rental revenue related to this lease agreement. During the years ended December 31, 2004 and 2003, TE Products also billed MB Storage $3.2 million and $2.5 million, respectively, for direct payroll and payroll related expenses for operating MB Storage. At December 31, 2004, TE Products had a net receivable balance from MB Storage of $1.3 million for operating costs, including payroll and related expenses for operating MB Storage. At December 31, 2003, TE Products had a net payable balance to MB Storage of $0.2 million for advances MB Storage paid for operating costs.
NOTE 8. INVENTORIES
Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at December 31, 2004 and 2003. The major components of inventories were as follows (in thousands):
NOTE 9. PROPERTY, PLANT AND EQUIPMENT
Major categories of property, plant and equipment for the years ended December 31, 2004 and 2003, were as follows (in thousands):
Depreciation expense on property, plant and equipment was $80.7 million, $64.5 million and $56.0 million for the years ended December 31, 2004, 2003 and 2002, respectively. During the fourth quarter of 2004, we wrote off approximately $2.1 million in assets taken out of service to depreciation expense.
We evaluate impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. During the third quarter of 2004, we completed an evaluation of our marine terminal facility in the Beaumont, Texas, area. The facility consists primarily of a barge dock, a ship dock, four storage tanks and various segments of connecting pipelines and is included in our Downstream Segment. The evaluation indicated that the docks and other assets at the facility needed extensive work to continue to be commercially operational. As a result, we performed an impairment test on the entire marine facility and recorded a $4.4 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the fair value of the facility.
NOTE 10. 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, 2004, TE Products was in compliance with the covenants of the TE Products Senior Notes.
On February 20, 2002, we completed 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. 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, 2004, we were in compliance with the covenants of these Senior Notes.
On January 30, 2003, we completed 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 are being 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 our $500.0 million revolving credit facility to $250.0 million. The balance of the net proceeds received was used for general partnership 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. As of December 31, 2004, we were in compliance with the covenants of these Senior Notes.
The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2004 and 2003 (in millions):
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. Interest Rate Swaps).
Other Long Term Debt and Credit Facilities
On April 6, 2001, we entered into a $500.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Three Year Facility”). 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 for the Three Year Facility contained certain restrictive financial covenant ratios. During the first quarter of 2003, we repaid $182.0 million of the outstanding balance of the Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under the Three Year Facility with borrowings under a new credit facility, and canceled the Three Year Facility.
On June 27, 2003, we entered into a $550.0 million revolving credit facility with a three year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”). 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 Revolving Credit Facility contains certain restrictive financial covenant ratios. We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. On October 21, 2004, we amended our Revolving Credit Facility to (i) increase the facility size to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing. On December 31, 2004, $353.0 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 3.0%. At December 31, 2004, we were in compliance with the covenants of this credit agreement.
The following table summarizes the principal amounts outstanding under all of our credit facilities as of December 31, 2004 and 2003 (in thousands):
NOTE 11. PARTNERS’ CAPITAL AND DISTRIBUTIONS
Equity Offerings
On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO. We received approximately $0.7 million in proceeds from the offering in excess of the amount needed to repurchase and retire the Class B Units.
On August 7, 2003, we sold in an underwritten public offering 5.0 million Units at $34.68 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $166.0 million. On August 19, 2003, 162,900 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on August 7, 2003. Proceeds from the over-allotment sale, net of underwriting discount, totaled $5.4 million. Approximately $53.0 million of the proceeds were used to repay indebtedness under our revolving credit facility and $21.0 million was used to fund the acquisition of the Genesis assets (see Note 5. Acquisitions and Dispositions). The remaining amount was used primarily to fund revenue-generating and system upgrade capital expenditures and for general partnership purposes.
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:
The following table reflects the allocation of total distributions paid during the years ended December 31, 2004, 2003 and 2002 (in thousands, except per Unit amounts):
On February 7, 2005, we paid a cash distribution of $0.6625 per Unit for the quarter ended December 31, 2004. The fourth quarter 2004 cash distribution totaled $58.7 million.
General Partner Interest
As of December 31, 2004 and 2003, we had deficit balances of $33.0 million and $7.2 million, respectively, in our General Partner’s equity account. This negative balance does not represent an asset to us and does not represent an obligation of the General Partner to contribute cash or other property to us. The General Partner’s equity account generally consists of its cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us (see our Consolidated Statements of Partners’ Capital for a detail of the General Partner’s equity account). For the years ended December 31, 2004 and 2003, the General Partner was allocated $41.1 million (representing 28.85%) and $34.8 million (representing 27.65%), respectively, of our net income and received $66.9 million and $54.7 million, respectively, in cash distributions.
Capital Accounts, as defined under our Partnership Agreement, are maintained for our General Partner and our limited partners. The Capital Account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under accounting principles generally accepted in the United States in our financial statements. Under our Partnership Agreement, the General Partner is required to make additional capital contributions to us upon the issuance of any additional Units if necessary to maintain a Capital Account balance equal to 1.999999% of the total Capital Accounts of all partners. At December 31, 2004 and 2003, the General Partner’s Capital Account balance substantially exceeded this requirement.
Net income is allocated between the General Partner and the limited partners in the same proportion as aggregate cash distributions made to the General Partner and the limited partners during the period. This is generally consistent with the manner of allocating net income under our Partnership Agreement. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under accounting principles generally accepted in the United States in our financial statements.
Cash distributions that we make during a period may exceed our net income for the period. 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. Cash distributions in excess of net income allocations and capital contributions during the years ended December 31, 2004 and 2003, resulted in a deficit in the General Partner’s equity account at December 31, 2004 and 2003. Future cash distributions that exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.
According to the Partnership Agreement, in the event of our dissolution, after satisfying our liabilities, our remaining assets would be divided among our limited partners and the General Partner generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of the Partnership. If a deficit balance still remains in the General Partner’s equity account after all allocations are made between the partners, the General Partner would not be required to make whole any such deficit.
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 each of the years ended December 31, 2004, 2003 and 2002, we had one customer from the Upstream Segment, Valero Energy Corp., which accounted for 16% of our total consolidated revenues. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2004, 2003 and 2002.
The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature.
NOTE 13. 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 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 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 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. Any unused balance previously credited is forfeited upon termination. We accrue compensation expense for the Performance Units awarded annually based upon the terms of the plan discussed above.
Under the agreement for such Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. At December 31, 2004, all options have been fully exercised. The Performance Unit account has a minimal liability balance which may be withdrawn by the participants after December 31, 2006.
A summary of Unit options granted under the terms of the 1994 LTIP is presented below:
We have not granted options for any periods presented. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised. For options previously 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 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 been immaterial for the year ended December 31, 2002, and no compensation expense would have been recognized for the years ended December 31, 2004 and 2003.
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 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 phantom 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 amount of the cash distribution that we paid per Unit to unitholders. A total of 1,800 phantom units granted under the 1999 PURP remain outstanding at December 31, 2004. A total of 57,600 phantom units granted under the 2002 PURP remain outstanding at December 31, 2004. We accrue compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above. At December 31, 2004 and 2003, we had an accrued liability balance of $1.6 million and $2.1 million, respectively, for compensation related to the 1999 PURP and 2002 PURP.
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 units granted under the award multiplied by (3) the average of the closing prices of a 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. At December 31, 2004, phantom units outstanding were 23,600, 30,600 and 21,200 for awards granted for the years ended December 31, 2004, 2003 and 2002, 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. For the years ended December 31, 2004 and 2003, EBITDA means, in addition to the above, earnings before other income - net. 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 operating oil supply and the gross value of intangibles and equity investments. Our cost of capital is approved by the Compensation 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 Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above. At December 31, 2004 and 2003, we had an accrued liability balance of $2.4 million and $2.9 million, respectively, for compensation related to the 2000 LTIP.
NOTE 14. OPERATING LEASES
We use leased assets in several areas of our operations. Total rental expense for the years ended December 31, 2004, 2003 and 2002, was $22.1 million, $18.8 million and $14.2 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 15. EMPLOYEE BENEFITS
Retirement Plans
We have adopted the TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”), which is a non-contributory, trustee-administered pension plan. In addition, certain executive officers participate in the TEPPCO
Supplemental Benefit Plan (“TEPPCO SBP”), which is a non-contributory, nonqualified, defined benefit retirement plan. The TEPPCO SBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. The benefit formula for all eligible employees is 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. We use a December 31 measurement date for these plans.
The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2004, 2003 and 2002, were as follows (in thousands):
Other Postretirement Benefits
Effective January 1, 2001, we provide employees with certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”). Employees become eligible for these benefits if they meet certain age and service requirements at retirement, as defined in the plans. We provide a fixed dollar contribution, which does not increase from year to year, towards retired employee medical costs. The retiree pays all health care cost increases due to medical inflation. We use a December 31 measurement date for this plan.
The components of net postretirement benefits cost for the TEPPCO OPB for the years ended December 31, 2004, 2003 and 2002, were as follows (in thousands):
We employ a building block approach in determining the long-term rate of return for plan assets. Historical markets are studied and long-term historical relationships between equities and fixed-income are preserved consistent with a widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. The long-term portfolio return is established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns are reviewed to check for reasonability and appropriateness.
The weighted average assumptions used to determine benefit obligations for the retirement plans and other postretirement benefit plans at December 31, 2004 and 2003, were as follows:
The weighted average assumptions used to determine net periodic benefit cost for the retirement plans and other postretirement benefit plans for the years ended December 31, 2004 and 2003, were as follows:
The following table sets forth our pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2004 and 2003 (in thousands):
Plan Assets
We employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, both growth and value equity style, and small, mid and large capitalizations. Investment risk and return parameters are reviewed and evaluated periodically to ensure compliance with stated investment objectives and guidelines. This comprehensive review incorporates investment portfolio performance, annual liability measurements and periodic asset/liability studies.
The following table sets forth the weighted average asset allocations for the retirement plans and other postretirement benefit plans as of December 31, 2004 and 2003, by asset category (in thousands):
We expect to contribute approximately $3.5 million to our retirement plans and other postretirement benefit plans in 2005.
Other Plans
DEFS also sponsors an employee savings plan, which covers substantially all employees. Plan contributions on behalf of the Company of $3.5 million, $3.2 million and $2.8 million were recognized during the years ended December 31, 2004, 2003 and 2002, respectively.
NOTE 16. 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 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. On January 27, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs and the Richards plaintiffs dismissing all of these plaintiffs’ claims. The settlement terms include a $2.0 million payment to the plaintiffs, which has been accrued for in our consolidated financial statements. The terms of the settlements did not have a material adverse effect on our financial position, results of operations or cash flows.
Although we did not settle with all plantiffs and we therefore remain named parties in the Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed to indemnify us for all remaining claims asserted against us. Consequently, we do not believe that the outcome of
these remaining claims will have a material adverse effect on our financial position, results of operations or cash flows.
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 plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’ petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The plaintiffs have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On 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. On July 16, 2003, the parties entered into a Settlement Agreement and Mutual Release, dismissing all claims and counterclaims against each other. The terms of the Settlement Agreement and Mutual Release did not have a material adverse effect on our financial position, results of operations or cash flows.
In May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are alleged to have suffered damages as the result of alleged exposure to asbestos-containing products and materials. According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual. The individual’s claims involve numerous employers and alleged job sites. The General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is uncertain at this time whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit. We cannot estimate the loss, if any, associated with this pending lawsuit. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.
On April 2, 2003, Centennial was served with a petition in a matter styled Adams, et al. v. Centennial Pipeline Company LLC, et al. This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill. The plaintiffs allege personal injuries, allergies, birth defects, cancer and death. The underground injection well has been in operation since May 1976. Based upon current information, Centennial appears to be a de minimis contributor, having used the disposal site during the two month time period of December 2001 to January 2002. Marathon has been handling this matter for Centennial under its operating agreement with Centennial. TE Products has a 50% ownership interest in Centennial. On November 30, 2004, the court approved a class settlement. The time period for parties to appeal this settlement has not expired, however, and the settlement will not be final until it does so. If the approved class settlement becomes final, the terms of the settlement will not have a material adverse effect on our financial position, results of operations or cash flows.
On December 16, 2003, Centennial, the General Partner, the Partnership and other Partnership entities were named as defendants in a lawsuit in the 128th District Court of Orange County, Texas, styled Elwood Karr et al. v. Centennial Pipeline, LLC et al. In this case, the plaintiffs contend that our pipeline leaked toxic substances on their property, causing them property damage. On October 29, 2004, the parties entered into a Settlement Agreement, dismissing all claims. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.
On February 4, 2005, we received a letter notifying us of a claim for approximately $1.45 million in damages allegedly due to a shipper being delivered off-specification gasoline during November 2004. We are contesting liability for this matter, and to the extent there may be liability, we would seek reimbursement from the third party refiner who supplied the gasoline into our pipeline system. We do not believe that the outcome of this matter will have a future material adverse effect on our consolidated financial position, results of operations or cash flows.
On February 7, 2005, we received a letter from BP Amoco’s counsel placing us on notice of a lawsuit filed by ConocoPhillips against BP Amoco Seaway Products Pipeline Company. Pursuant to provisions of the Amended and Restated Purchase Agreement dated May 10, 2000, between us and ARCO Pipe Line Company (BP Amoco), BP Amoco requested indemnity should BP Amoco have any liability to ConocoPhillips. The litigation arises out of an income tax liability alleged by ConocoPhillips due to a partnership merger. The plaintiff estimates the income tax liability to be $3,964,788. We have requested information from BP Amoco that will allow us to assess liability, if any, that we may have in this matter. We do not believe that the outcome of this lawsuit will have a future material adverse effect on our consolidated 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.
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.
On March 26, 2004, an initial decision in ARCO Products Co., et al. v. SFPP, Docket OR96-2-000, et al. was issued by the FERC, which made several significant determinations with respect to finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”). The decision largely clarifies, but does not fully quantify, the standard required for a complainant to demonstrate that an oil pipeline’s rates are no longer subject to the rate protection of the EP Act by demonstrating that a substantial change in circumstances has occurred since 1992 with respect to the basis of the rates being challenged. In the decision, the FERC found that a limited number of rate elements will significantly affect the economic basis for a pipeline company’s rates. The elements identified in the decision are volume changes, allowed total return and total cost-of-service (including major cost elements of rate base such as tax rates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rate and income tax allowances as standalone factors. It appears likely that the decision will be appealed. We have not yet determined the impact, if any, that the decision, if it is ultimately upheld, would have on our rates if they were reviewed under the criteria of this decision.
On July 20, 2004, the Court of Appeals for the District of Columbia Circuit issued an opinion in BP West Coast Producers LLC v. FERC. In reviewing a series of orders involving SFPP, L.P. the court held among other things that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. Under the FERC’s initial ruling, SFPP, L.P. was permitted an income tax allowance on its cost-of-service filing for 42.7% of the net operating (pre-tax) income expected from operations and was denied an income tax allowance equal to 57.3% of its limited partnership interests that were held by non-corporate partners. The court remanded the case back to the FERC for further review. As a result of the court’s remand, the FERC on December 2, 2004, issued a Request for Comments seeking comments on whether the court’s ruling applies only to the specific facts of the SFPP, L.P. proceeding or also extends to other capital structures involving partnerships and other forms of ownership. The ultimate outcome of the FERC’s inquiry on income tax allowance should not affect our current rates and rate structure because our rates are not based on cost-of-service methodology. However, the outcome of the income tax allowance would become relevant to us should we (i) elect in the future to use cost-of-service to support our rates, or (ii) be required to use such methodology to defend our indexed rates.
In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. At December 31, 2004, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. Effective in March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.
On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a storage tank at our Blue Island terminal located in Cook County, Illinois. As a result of the release, we have entered into an Agreed Order with the State of Illinois which required us to conduct an environmental investigation. At this time, we have complied with the terms of the Agreed Order, and the results of the environmental investigation indicated there were no soil or groundwater impacts from the release. We are in the process of negotiating a final settlement with the State of Illinois, and we do not expect that compliance with the settlement will have a future material adverse effect on our financial position, results of operations or cash flows.
On July 22, 2004, we experienced a release of approximately 12 barrels of jet fuel from a sump at our Lebanon, Ohio, terminal. The released jet fuel was contained within a storm water retention pond located on the terminal property. Six migratory waterfowl were affected by the jet fuel and were subsequently euthanized by or at the request of the United States Fish and Wildlife Service (“USFWS”). On October 1, 2004, the USFWS served us with a Notice of Violation, alleging that we violated 16 USC 703 of the Migratory Bird Treaty Act for the “take[ing] of migratory birds by illegal methods.” On February 7, 2005, we entered into a Memorandum of Understanding with the USFWS, settling all aspects of this matter. The terms of this settlement did not have a material effect on our financial position, results of operations or cash flows.
On July 27, 2004, we received notice from the United States Department of Justice (“DOJ”) of its intent to seek a civil penalty against us related to our November 21, 2001, release of approximately 2,575 barrels of jet fuel from our 14-inch diameter pipeline located in Orange County, Texas. The DOJ, at the request of the Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release. The maximum statutory penalty calculated for this alleged violation of the CWA is $2.8 million. We are in discussions with the DOJ regarding this matter and have responded to its request for additional information. We do not expect a civil penalty, if any, to have a material adverse effect on our financial position, results of operations or cash flows.
At December 31, 2004, we have an accrued liability of $5.0 million, related to various TCTM and TE Products sites requiring environmental remediation activities. At December 31, 2003, we had an accrued liability of $5.9 million related to various TCTM sites requiring environmental remediation activities. Under the terms of a 1998 agreement through which we acquired various crude oil assets from DETTCO, we received a five year contractual indemnity obligation for certain environmental liabilities attributable to the operations of the assets prior to our acquisition. Concurrent with the expiration of this indemnity in 2003, we entered into a Settlement Agreement and Release with DETTCO releasing DETTCO from future obligations pertaining to certain environmental liabilities, requiring us to share in certain costs for the remediation of a crude oil site in Oklahoma, and the assumption of responsibility by DETTCO for environmental liabilities associated with three sites located in Texas and Oklahoma. We do not expect that the completion of remediation programs associated with TCTM and TE Products 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, 2004, $150.0 million was outstanding under those credit facilities. The proceeds were used to fund construction and conversion
costs of its pipeline system. TE Products and Marathon have each guaranteed one-half of Centennial’s debt, up to a maximum amount of $75.0 million each.
Rates of interstate 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. On April 22, 2003, several shippers filed a petition in the United States Court of Appeals for the District of Columbia Circuit (the “Court”), Flying J. Inc,. Lion Oil Company, Sinclair Oil Corporation and Tesoro Refining and Marketing Company vs. Federal Energy Regulatory Commission; Docket No. 03-1107, seeking a review of whether the FERC’s adoption of the PPI Index was reasonable and supported by the evidence. On April 9, 2004, the Court handed down a decision denying the shippers’ petition for review, stating the shippers failed to establish that any of the FERC’s methodological choices (or combination of choices) were both erroneous and harmful.
As an alternative to using the PPI Index, interstate 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 petroleum products and crude oil pipeline companies that the rate is acceptable.
Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2004, TCTM and TE Products had approximately 2.9 million barrels and 20.8 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.
We carry insurance coverage consistent with companies engaged in similar operations with similar type properties. Our insurance coverage includes (1) commercial general public liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from earthquake, flood damage and business interruption/extra expense. For select assets, we also carry pollution liability insurance that provides coverage for historical and gradual pollution events. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of our general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets. These insurance policies, except for the pollution liability policies, are with Bison Insurance Company Limited, an insurance company that is wholly owned by Duke Energy (see Note 7. Related Party Transactions).
NOTE 17. SEGMENT INFORMATION
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 intersegment eliminations and assets that we hold that have not been allocated to any of our reporting segments.
Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, 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 the results of operations of the northern portion of the Dean Pipeline, which transports, refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6. Equity Investments).
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, New Mexico 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 transportation logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes our equity investment in Seaway. Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas.
Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde. DEFS manages and operates the Val Verde, Jonah and Chaparral assets for us under contractual agreements. The results of operations of the acquisitions are included in our consolidated financial statements in periods subsequent to their respective acquisition dates (see Note 5. Acquisitions and Dispositions).
The tables below include financial information by reporting segment for the years ended December 31, 2004, 2003 and 2002 (in thousands):
The following table provides the total assets, capital expenditures and significant non-cash investing activites for each segment as of and for the years ended December 31, 2004, 2003 and 2002 (in thousands):
The following table reconciles the segments total earnings before interest to consolidated net income for the three years ended December 31, 2004, 2003 and 2002 (in thousands):
NOTE 18. 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, 2004, 2003 and 2002, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which was designated as a cash flow hedge. The interest rate swap matured in April 2004. While the interest rate swap was in effect, changes in the fair value of the cash flow hedge, to the extent the hedge was effective, were recognized in other comprehensive income until the hedge interest costs were recognized in net income. As of December 31, 2004, all other comprehensive income has been recognized in net income.
The table below reconciles reported net income to total comprehensive income for the years ended December 31, 2004, 2003 and 2002 (in thousands):
The accumulated balance of other comprehensive loss related to our cash flow hedge is as follows (in thousands):
NOTE 19. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Our significant operating subsidiaries, 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., have 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.
NOTE 20. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(1) The sum of the four quarters does not equal the total year due to rounding.
(2) Per Unit calculation includes 3,938,750 Units issued in April 2003, 3,916,547 Units repurchased and retired in April 2003, 5,162,900 Units issued in August 2003, and 87,307 Units issued through the exercise of Unit options in 2003.
NOTE 21. SUBSEQUENT EVENT
On February 24, 2005, Texas Eastern Products Pipeline Company, LLC, our General Partner, was acquired by EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan. The acquisition was valued at $1.1 billion. Additionally, in a separate transaction, EPCO and its affiliates have agreed to purchase 2.5 million of our Units, valued at approximately $100.0 million, from Duke Energy. EPCO and its affiliates own the general partner of Enterprise Products Partners L.P. (“Enterprise”) and approximately 145 million Enterprise common units. Enterprise is one of the largest publicly traded master limited partnerships. The general partners of both TEPPCO Partners, L.P. (“TEPPCO”) and Enterprise will continue to operate independently and will maintain separate boards of directors, management teams and offices.