ITEM 3. LEGAL PROCEEDINGS
We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on the financial condition or results of our operations. For information on the settlement of litigation with Pennzoil see Management's Discussion and Analysis - Other Matters on page 39.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders during the fiscal year covered by this report.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED SECURITY HOLDER MATTERS
The Common Units are listed on the American Stock Exchange under the symbol "GEL". The following table sets forth, for the periods indicated, the high and low sale prices per Common Unit and the amount of cash distributions paid per Common Unit.
---------- (1) Cash distributions are shown in the quarter paid and are based on the prior quarter's activities.
(2) A special distribution of $0.20 per unit was paid on December 16, 2002 to mitigate potential taxable income allocations to Unitholders.
At December 31, 2003, there were 9,313,811 Common Units outstanding, including 688,811 Common Units held by our General Partner. As of December 31, 2003, there were approximately 6,500 record holders and beneficial owners (held in street name) of our Common Units.
We distribute all of our Available Cash as defined in the Partnership Agreement within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements, adjusted for net changes to cash reserves. Cash reserves are the amounts deemed necessary or appropriate, in the reasonable discretion of our general partner, to provide for the proper conduct of our business or to comply with applicable law, any of our debt instruments or other agreements. The full definition of Available Cash is set forth in the Partnership Agreement and amendments thereto, which is filed as an exhibit to this Form 10-K.
Our target minimum quarterly distribution is $0.20 per Common Unit. In addition to its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.
In 2001, we announced that we would not pay a distribution for the fourth quarter of 2001, which would normally have been paid in February 2002. We did not pay regular distributions for 2002. We paid a special distribution in the fourth quarter of 2002 to mitigate potential taxable income allocations to unitholders. In 2003, we began paying quarterly distributions again with distributions for the first quarter of 2003 of $0.05 per unit. For the fourth quarter of 2003, we increased our distribution to $0.15 per unit (which was paid in February 2004).
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The table below includes selected financial data for the Partnership for the years ended December 31, 2003, 2002, 2001, 2000, and 1999 (in thousands, except per unit and volume data).
(1) At the end of 2001, we changed our business model to substantially eliminate bulk and exchange transactions due to relatively low margins and high credit requirements.
(2) In 2001, we recorded an impairment charge of $45.1 million, with $35.5 million of that amount included in discontinued operations. This impairment charge related to goodwill and our pipeline operations.
(3) Maintenance capital expenditures are capital expenditures to replace or enhance partially or fully depreciated assets to sustain the existing operating capacity or efficiency of our assets and extend their useful lives.
(4) Represents average daily volume for the two month period that we owned the assets.
The table below summarizes our quarterly financial data for 2003 and 2002 (in thousands, except per unit data).
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Included in Management's Discussion and Analysis are the following sections:
- Overview of 2003
- Critical Accounting Policies
- Results of Operations and Outlook for 2004 and Beyond
- Liquidity and Capital Resources
- Commitments and Off-Balance Sheet Arrangements
- Other Matters
- New Accounting Pronouncements
In the discussions that follow, we will focus on two measures that we use to manage the business and to review the results of our operations. Those two measures are segment margin and available cash. Our profitability depends to a significant extent upon our ability to maximize segment margin. Segment margin is calculated as revenues less cost of sales and operating expense, and does not include depreciation and amortization. A reconciliation of Segment Margin to income from continuing operations is included in our segment disclosures in Note 8 to the consolidated financial statements. Available Cash is a non-GAAP liquidity measure calculated as net income with several adjustments, the most significant of which are the elimination of gains and losses on asset sales, except those from the sale of surplus assets, the addition of non-cash expenses such as depreciation, and the subtraction of maintenance capital expenditures, which are expenditures to sustain existing cash flows but not to provide new sources of revenues. For additional information on Available Cash and a reconciliation of this measure to cash flows from operations, see "Non-GAAP Financial Measure" below.
OVERVIEW OF 2003
Genesis Energy, L.P. is a Delaware limited partnership that is publicly traded on the American Stock Exchange. We operate through Genesis Crude Oil, L.P., and its subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline, USA, L.P. Our operations are managed through our general partner, Genesis Energy, Inc., a wholly-owned indirect subsidiary of Denbury Resources Inc. The general partner holds a 2% general partner interest and a 7.25% limited partner interest and public unitholders hold an aggregate 90.75% limited partner interest in Genesis Energy, L.P.
We operate in three business segments - crude oil gathering and marketing, crude oil pipeline transportation and CO2 marketing. Our revenues are earned by selling crude oil and CO2 and by charging fees for the transportation of crude oil on our pipelines. Our focus is on the margin we earn on these revenues, which is calculated by subtracting the costs of the crude oil, the costs of transporting the crude oil and CO2 to the customer, and the costs of operating our assets.
Our primary goal is to generate Available Cash for our unitholders. This Available Cash is then distributed quarterly to our unitholders. We are pleased with the progress we made in 2003 toward our goal of generating more stable sources of Available Cash. Two significant actions that we took in 2003 toward this goal were:
- Disposing of our Texas Gulf Coast operations
- Purchasing a CO2 volumetric production payment and related marketing contracts.
During the fourth quarter of 2003, we closed the sale of portions of our Texas Gulf Coast operations to TEPPCO Crude Pipeline, L.P. We also sold portions of our Texas pipeline system that we idled in 2002 to Blackhawk Pipeline, L.P. We abandoned in place other portions of the Texas pipeline system. The sale of these operations was the result of an initiative we started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce costs or risks of operation, and which segments we should invest in for future growth. As a result of these actions we recorded a gain on the disposal of these discontinued operations of $13.0 million.
The sale of the Texas Gulf Coast operations to TEPPCO benefited both parties almost immediately. TEPPCO realized benefits from integrating these assets into their existing South Texas pipeline system. By selling
these assets, we reduced 2004 projected maintenance expenditures by $6.6 million and eliminated potential risks to the continuation of our revenue stream that may have resulted from consolidation of pipeline assets in the area. We believe that these assets had more long-term strategic benefit to TEPPCO than to us.
The pipeline segments sold to Blackhawk were assets that we idled in 2002 due to declining volumes and/or risks of operation. We received no proceeds from this sale. By making the sale to Blackhawk, we eliminated costs of maintaining the assets. Blackhawk intends to convert the pipeline segments to natural gas service.
The segments we abandoned in place had not been in service since 2002 and this abandonment reduces our costs for monitoring and maintenance. Additionally, this abandonment helped to offset tax gains allocated to our unitholders from the sale to TEPPCO.
The carbon dioxide (CO2) volumetric production payment we purchased enables us to commence a wholesale CO2 marketing operation. We acquired this production payment, as well as related long-term CO2 industrial sales contracts, from Denbury. While this CO2 operation will have some seasonality, the cash flows from this operation will be much less volatile than those of our existing crude oil gathering and marketing operation.
The funds to acquire this production payment came from the $21 million received from TEPPCO for the sale of the Texas Gulf Coast operations and the issuance of 688,811 limited partner units to our general partner in exchange for $5.0 million.
Our continuing operations did not perform as well as expected. Volatility in P-Plus market prices for crude oil has historically created fluctuations in our segment margins. During 2003, we experienced positive results when P-Plus market prices increased in the early part of the year; however, a precipitous decline in segment margin during the latter half of the year offset some of the segment margin earned in the first half of the year.
Revenues from our pipeline transportation operations increased primarily due to tariff increases in 2002 and 2003.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from those 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 and estimates are those that are most important to the portrayal of our financial results and positions. These policies require management's judgment and often employ the use of information that is inherently uncertain. Our most critical accounting policies pertain to revenue and expense accruals, pipeline loss allowance recognition, depreciation, amortization and impairment of long-lived assets and contingent and environmental liabilities. These policies are discussed below.
Revenue and Expense Accruals
Information needed to record our revenues is generally available to allow us to record substantially all of our revenue-generating transactions based on actual information. The accruals that we are required to make for revenues are generally insignificant.
We routinely make accruals for expenses due to the timing of receiving third party information and reconciling that information to our records. These accruals can include some crude oil purchase costs and expenses for operating our assets such as contractor charges for goods and services provided. For crude oil purchases transported on our trucks or our pipelines, we have access to the volumetric and pricing data so that we can record these transactions based on actual information. Accounting for crude oil purchases that involve third party transportation services sometimes require us to make estimates, as the necessary volumetric data is not available within the timeframe needed. By balancing our crude oil purchase and sales volumes with the change in our inventory positions, we believe we can make reasonable estimates of the unavailable data.
The provisions of SFAS No. 133, as amended, require that estimates be made of the effectiveness of derivatives as hedges and the fair value of derivatives. The actual results of the transactions involving the derivative instruments will most likely differ from the estimates. We make very limited use of derivative instruments; however, when we do, we base these estimates on information obtained from third parties and from our own internal records.
We believe our estimates for revenue and expense items are reasonable, but there can be no assurance that actual amounts will not vary from estimated amounts.
Pipeline Loss Allowance Recognition
Numerous factors can cause crude oil volumes to expand and contract. These factors include temperature of both the crude oil and the surrounding atmosphere and the quality of the crude oil, in addition to inherent imprecision of measurement equipment. As a result of these factors, crude oil volumes fluctuate, which can result in losses in volumes of crude oil in the custody of the pipeline that belongs to the shippers. In order to compensate the pipeline for bearing the risk of actual losses in volumes that occur, the pipeline generally has established in its tariffs the right to make volumetric deductions from the shippers for quality and volumetric fluctuations. These deductions are referred to as pipeline loss allowances.
These allowances are compared to the actual volumetric gains and losses of the pipeline and the net gain or loss is recorded as revenue or expense, based on prevailing market prices at that time. When net gains occur, the pipeline company has crude oil inventory. When net losses occur, any recorded inventory on hand is reduced and the pipeline records a liability for the purchase of crude oil that it must make to replace the lost volumes. Inventories are reflected in the financial statements at the lower of the recorded value or the market value at the balance sheet date. Liabilities to replace crude oil are valued at current market prices. The crude oil in inventory can then be sold, resulting in additional revenue if the sales price exceeds the inventory value.
Future pipeline loss allowance revenue cannot be predicted, as it depends on factors beyond management's control such as the crude oil quality and temperatures, as well as crude oil market prices.
Depreciation, Amortization and Impairment of Long-Lived Assets
In order to calculate depreciation and amortization we must estimate the useful lives of our fixed assets at the time the assets are placed in service. Calculation of the useful life of an asset is based on our experience with similar assets. Experience, however, can cause us to change our estimates, thus impacting the future calculation of depreciation and amortization.
When events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, we review our assets for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. We compare the carrying value of the fixed asset to the estimated undiscounted future cash flows expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. Should the undiscounted future cash flows be less than the carrying value, we record an impairment charge to reflect the asset at fair value.
Liability and Contingency Accruals
We accrue reserves for contingent liabilities including environmental remediation and potential legal claims. When our assessment indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated, accruals are made. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome, including consultation with external experts and counsel. These estimates are revised as additional information is obtained or resolution is achieved.
In 2001, we recorded an estimate of $1.5 million for the potential liability for fines related to the crude oil spill in December 1999 from our Mississippi pipeline system. After assessing information obtained in meetings with the government, this estimate was increased to a total of $3.0 million in 2002.
We also make estimates related to future payments for environmental costs to remediate existing conditions attributable to past operations. Environmental costs include costs for studies and testing as well as remediation and restoration. These estimates are sometimes made with the assistance of third parties involved in monitoring the remediation effort.
We have recorded an estimate for the additional costs expected to be incurred to complete the remediation of the site of the Mississippi crude oil pipeline spill. This estimate is based upon expectations of the additional work to be performed to meet regulatory requirements and restore the site. Because the costs of remediation and restoration for this spill are covered by insurance, we record a receivable from the insurers for a similar amount.
We believe our estimates for contingent liabilities are reasonable, but there can be no assurance that actual amounts will not vary from estimated amounts.
RESULTS OF OPERATIONS AND OUTLOOK FOR 2004 AND BEYOND
The following table summarizes financial data by segment for the years ended December 31, 2003, 2002 and 2001 (in thousands).
CRUDE OIL GATHERING AND MARKETING OPERATIONS
The key drivers affecting our crude oil gathering and marketing segment margin include production volumes, volatility of P-Plus, volatility of grade differentials, inventory management, and credit costs.
Segment margins from gathering and marketing operations are a function of volumes purchased and the difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale, minus the associated costs of aggregation and transportation. The absolute price levels for crude oil do not necessarily bear a relationship to segment margin as absolute price levels normally impact revenues and cost of sales by equivalent amounts. Because period-to-period variations in revenues and cost of sales are not generally
meaningful in analyzing the variation in segment margin for gathering and marketing operations, such changes are not addressed in the following discussion.
In our gathering and marketing business, we seek to purchase and sell crude oil at points along the Distribution Chain where we can achieve positive margins. We generally purchase crude oil at prevailing prices from producers at the wellhead under short-term contracts. We then transport the crude along the Distribution Chain for sale to or exchange with customers. Additionally, we enter into exchange transactions with third parties, generally only when the cost of the exchange is less than the alternate cost we would incur in transporting or storing the crude oil. In addition, we often exchange one grade of crude oil for another to maximize margins or meet contract delivery requirements. Prior to the first quarter of 2002, we purchased crude oil in bulk at major pipeline terminal points. These bulk and exchange transactions were characterized by large volumes and narrow profit margins on purchases and sales.
Generally, as we purchase crude oil, we simultaneously establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases, on the one hand, and sales or future delivery obligations, on the other hand. It is our policy not to hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes.
A significant factor affecting our gathering and marketing segment margins is the change in domestic production of crude oil. Short-term and long-term price trends impact the amount of capital that oil producers have available to maintain existing production and to invest in developing crude reserves, which in turn impacts the amount of crude oil that is available to be gathered and marketed by us and our competitors. During the last two years, posted prices for West Texas Intermediate crude oil have ranged from a low near $16 per barrel to a high of $32 per barrel. The volatility in prices over the last two years makes it very difficult to estimate the volume of crude oil available to purchase. We expect to continue to be subject to volatility and long-term declines in the availability of crude oil production for purchase.
Crude oil prices in the United States are impacted by both international factors as well as domestic factors. International factors such as wars and conflicts, instability of foreign governments, and labor strikes affect prices, as do the influences in the U.S. of environmental regulations and the supply of domestic production. An increase in the market price of crude oil does not impact us to the extent many people expect. When market prices for oil increase, we must pay more for crude oil, but we normally are able to sell it for more.
Most of our contracts for the purchase and sale of crude oil have components in the pricing provisions such that the price paid or received is adjusted for changes in the market price for crude oil. Often the pricing in a contract to purchase crude oil will consist of the market price component and a bonus, which is generally a fixed amount ranging from a few cents to several dollars. Typically the pricing in a contract to sell crude oil will consist of the market price component and a bonus that is not fixed, but instead is based on another market factor. This floating bonus is usually the price quoted by Platt's for WTI "P-Plus". Because the bonus for purchases of crude oil is fixed and P-Plus floats in the sales contracts, the margin on individual transactions can vary from month-to-month depending on changes in the P-Plus component.
P-Plus does not necessarily move in correlation with the price of crude oil in the market. P-Plus is affected by numerous factors such as future expectations for changes in crude oil prices, such that crude oil prices can be rising, but P-Plus can be decreasing. The table below shows the average P-Plus and the average posted price for West Texas Intermediate (WTI) as posted by Koch Supply & Trading, L.P. by quarter in 2003, 2002 and 2001, based on the simple averaging of the monthly averages.
As can be seen from this table, changes in P-Plus do not necessarily correspond to changes in the market price of oil. An example is the decline in P-Plus between the third and fourth quarters of 2003 when the WTI posting increased. This unpredictable volatility in P-Plus can create volatility in our earnings.
A few purchase contracts and some sale contracts also include a component for grade differentials. The grade refers to the type of crude oil. Crude oils from different wells and areas can have different chemical compositions. These different grades of crude oil will appeal to different customers depending on the processing capabilities of the refineries that ultimately process the crude oil. We may buy crude oil under a contract where we considered the typical grade differences in the market when we set the fixed bonus. If we then sell the oil under a contract with a floating grade differential in the formula, and that grade differential fluctuates, then we can experience an increase or decrease in our margin from that oil purchase and sale. The table below shows the grade differential between West Texas Intermediate grade crude oil and West Texas Sour grade crude oil, using the monthly averages for each quarter of 2001, 2002 and 2003, and the differential between West Texas Intermediate grade crude oil and Light Louisiana Sweet grade crude oil for the same periods.
As can be seen from this table, the WTI/WTS market differential varied from $1.028 per barrel in the third quarter of 2002 to $3.810 per barrel in second quarter of 2001. The WTI/LLS market differential varied from a negative $0.323 per barrel in the third quarter of 2002 to a positive $0.460 in the first quarter of 2003. This volatility in grade differentials can affect the volatility of our gathering and marketing segment margin.
Our purchase and sales contracts are primarily "Evergreen" contracts, which means they continue from month to month unless one of the parties to the contract gives 30-days notice of cancellation. In order to change the pricing in a fixed bonus contract, we would have to give 30-days notice that we want to cancel or renegotiate the contract. This notice time requirement, therefore, means that at least a month will pass before the fixed bonus can be reduced to correspond with a decrease in the P-Plus component of the related sales contract. In this case, our margin would be reduced until such a change is made. Because of the volatility of P-Plus, it is not practical to renegotiate every purchase contract for every change in P-Plus. So segment margins from the sale of the crude oil may be volatile as a result of these timing differences.
Another factor that can contribute to volatility in our earnings is inventory management. Generally contracts for the purchase of crude oil will state that we will buy all of the production for the month from a particular well. We generally aggregate the volumes purchased from numerous wells and deliver it into a pipeline where we sell the crude oil to a third party. While oil producers can make estimates of the volume of oil that their wells will produce in a month, they cannot state absolutely how much oil will be produced. Our sales contracts typically state a specific volume to be sold. Consequently, if a well produces more than expected, we will purchase volumes in a month that we have not contracted to sell. These volumes are then held as inventory and are sold in a later month. Should the market price of crude oil fluctuate while we have these inventory volumes, we may have to recognize a loss in our financial statements should the market price fall below the cost of the inventory. Should market prices rise, then we will realize a gain when we sell the unexpected volume of inventory in a later month at higher prices. We make every effort to limit our exposure to these price fluctuations by minimizing inventory volumes.
Year Ended December 31, 2003 as Compared to Year Ended December 31,
Gathering and marketing segment margins decreased $3.3 million or 29% to $7.9 million for the year ended December 31, 2003, as compared to $11.2 million for the year ended December 31, 2002.
A 22 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a $5.3 million decrease in segment margin, was the primary reason for this decrease.
Factors offsetting this decrease were:
- A $1.6 million increase in segment margin due to an increase in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; and
- a $0.4 million decrease in field operating costs, primarily from a $0.5 million decrease in payroll and benefits, offset by a $0.1 million increase in repair costs. The decreased payroll-related costs can be attributed to an approximate 6 percent decrease in the wellhead volumes. The increase in repair costs is attributable primarily to repairs at truck unloading stations.
Although P-Plus declined significantly in the latter half of 2003, the average for 2003 of $4.065 per barrel was 25% higher than the average for 2002 of $3.261 per barrel. This price increase was not enough however to offset the decline in volumes.
We changed our business model in 2002 to substantially eliminate our bulk and exchange activity due to the relatively low margins and high credit requirements for these transactions. Additionally, we reviewed our wellhead purchase contracts to determine whether margins under those contracts would support higher credit costs. In some cases, contracts were cancelled. These volume reductions began in late 2001 and continued into the first half of 2002. Volumes beginning in the third quarter of 2002 have remained relatively stable at an average of 57,500 barrels per day. For the fourth quarter of 2003, daily volumes were 61,400 barrels. The change in our business model was the primary reason crude oil gathering and marketing volumes decreased by 23%.
Field operating costs primarily consist of the costs to operate our fleet of 49 trucks used to transport crude oil, and the costs to maintain the trucks and assets used in the crude oil gathering operation. Approximately 55% of these costs are variable and decline when volumes decline. Such costs include payroll and benefits (as drivers are paid on a commission basis based on volumes), maintenance costs for the trucks (as we lease the trucks under full service maintenance contracts under which we pay a maintenance fee per mile driven), and fuel costs. Fixed costs include the base lease payment for the vehicle, insurance costs and costs for environmental and safety related items.
Year Ended December 31, 2002 as Compared to Year Ended December 31,
Gathering and marketing segment margins increased $1.4 million or 15% to $11.2 million for the year ended December 31, 2002, as compared to $9.7 million for the year ended December 31, 2001.
The factors increasing segment margin were:
- an $18.4 million increase in segment margin due to an increase in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale; and
- an $0.8 million decrease in credit costs primarily due to the reduction in bulk and exchange transactions.
Largely offsetting these increases were:
- a 77 percent decrease in wellhead, bulk and exchange purchase volumes between 2001 and 2002, resulting in a decrease in segment margin of $17.1 million; and
- a $0.7 million increase in field operating costs, primarily from a $0.3 million increase in payroll and benefits, a $0.2 million increase in repair costs, a $0.1 million increase in vehicle lease costs, and a $0.1 million increase in insurance costs. The increased payroll-related costs can be attributed to an increase in benefit costs and an increase in the miles driven in our trucks. The increased lease costs are attributable to increases in the number of vehicles and in the miles driven. The increase in repair costs is attributable primarily to repairs at truck unloading stations. The increased insurance costs reflect a combination of changes in the insurance market and our loss history.
As discussed previously, we eliminated transactions with low margins and high credit costs. These volume reductions were the primary reasons gathering and marketing volumes decreased by 77% in the 2002 period.
Outlook for 2004 and Beyond
Volatility in P-Plus will continue. During 2004, we expect our crude oil gathering and marketing business to generate at least as much segment margin as it did in 2003; however, no assurance can be made that this will occur. Our plans include increasing volumes by acquiring new production and production currently being gathered by other parties.
CRUDE OIL PIPELINE OPERATIONS
We operate three common carrier pipeline systems in a five state area. We refer to these pipelines as our Texas System, Mississippi System and Jay System. Volumes shipped on these systems for the last three years are as follows (barrels per day):
In 2003, we sold or abandoned significant portions of our Texas System. The segments we retained and continue to operate are from West Columbia to Webster, Cullen Junction to Webster, and from Webster to Texas City, and Webster to a shipper's facility in Houston. Information on the segments sold or abandoned is discussed in the section "Discontinued Operations" below. The following information pertains only to continuing operations.
Volumes on our Texas System averaged 43,388 barrels per day in 2003. The crude oil that enters our system comes to us at West Columbia and Cullen Junction where we have connections to TEPPCO's South Texas System and at Webster where we have a connection with another pipeline. Under the terms of our sale to TEPPCO of portions of the pipeline, we have a joint tariff with TEPPCO through September 2004 under which we earn $0.40 per barrel on the majority of the barrels we deliver to the shipper's facilities and $0.50 per barrel on heavier crude oil we deliver. Most of the volume being shipped on our Texas System goes to three refineries on the Texas Gulf Coast. We are still shipping most of the same volumes that we were shipping before the sale to TEPPCO, however our tariff revenue is much less than before the sale, as we ship the crude oil a shorter distance.
The Mississippi System is best analyzed in two segments. The first segment is the portion of the pipeline that begins in Soso, MS and extends to Liberty, MS. At Liberty, shippers can transfer the crude oil to a connection to Capline, a pipeline system that moves crude oil from the Gulf Coast to refineries in the Midwest. The segment from Soso to Liberty has also been improved to handle the increased volumes produced by Denbury and transported on the pipeline. In order to handle future increases in production volumes in the area that are expected, we have made capital expenditures for tank, station and pipeline improvements and we will need to make further improvements. See Capital Expenditures under "Liquidity and Capital Resources" below.
The second segment of the pipeline from Liberty to near Baton Rouge, LA has been out of service since February 1, 2002 while a connecting carrier tested its pipeline. The connecting carrier has decided not to reactivate its pipeline, so we will displace the crude oil in this segment with inhibited water until the connecting carrier either make repairs or we identify an alternative use for this segment. The cost of this displacement is being paid for by the owner of the crude oil. In 2003, this segment made no contribution to pipeline revenues. In 2002 and 2001, this segment of pipeline contributed $0.1 million and $1.5 million, respectively, to pipeline revenues. Volumes on this segment in 2001 were over 14,400 barrels per day.
The Jay pipeline system in Florida/Alabama ships crude oil from fields with relatively short remaining production lives. Volumes have declined from an annual average of 19,294 per day in 2001, to 16,455 in 2002 to 15,128 in 2003. Many of the costs to operate our pipeline are fixed costs, including the costs of compliance with environmental regulations and the costs of insurance, so the decline in volumes has necessitated increases in tariffs. The only shipper on the largest portion of the pipeline has agreed to tariff rate increases in 2002 and 2003 that have helped offset the declines in the volumes and increased costs of operating this pipeline.
Historically, the largest operating costs in our crude oil pipeline segment have consisted of personnel costs, power costs, maintenance costs and costs of compliance with regulations. Some of these costs are not predictable, such as failures of equipment, or are not within our control, like power cost increases. We perform regular maintenance on our assets to keep them in good operational condition to minimize any cost increases.
Year Ended December 31, 2003 Compared with Year Ended December 31,
Pipeline segment margin decreased $0.3 million or 6% to $5.1 million for the year ended December 31, 2003, as compared to $5.4 million for the year ended December 31, 2002. The factors decreasing pipeline segment margin were:
- a 7 percent decrease in throughput between the two years, resulting in a revenue decrease of $0.8 million; and
- a $1.9 million increase in pipeline operating costs in 2003. In the third quarter we recorded an asset retirement obligation of $0.7 million related to an offshore pipeline. Pipeline operating costs increased $0.1 million for personnel and benefits costs related to addition as of operations staff in Mississippi and additions of staff engineers, and $0.1 million for costs associated with work vehicles for the new staff. Costs associated with maintenance of right-of ways, including clearing of tree canopies, and costs for testing under pipeline integrity regulations increased a combined $0.2 million. In 2003, we increased safety training for pipeline operations personnel at a cost of $0.3 million. Insurance costs increased $0.2 million due to the combination of insurance market conditions and our loss history. Other operating costs, including power costs increased a total of $0.3 million.
Partially offsetting these decreases were the following factors:
- a 22 percent increase in the average tariff on shipments resulting in a $2.3 million increase in revenue; and
- a $0.1 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of higher crude oil market prices resulting in more revenue on these volumes.
Year Ended December 31, 2002 Compared with Year Ended December 31,
Pipeline segment margin increased $2.5 million or 86% to $5.4 million for the year ended December 31, 2002, as compared to $2.9 million for the year ended December 31, 2001. The factors increasing pipeline segment margin were:
- a 35 percent increase in the average tariff on shipments resulting in a $2.9 million increase in revenue; and
- a $1.6 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of revising pipeline tariffs to increase the amount of the pipeline loss allowance imposed on shippers, and the recognition of pipeline loss allowance volumes, measurement gains net of measurement losses, and crude quality deductions as inventory.
Partially offsetting these increases were:
- an 11 percent decrease in throughput between the two years, resulting in a revenue decrease of $1.0 million; and
- a $1.0 million increase in pipeline operating costs in 2002 primarily due to greater expenditures for personnel and benefits, for maintenance of right-of-ways including clearing of tree canopies and costs associated with residential and commercial development around our pipelines, for testing under the pipeline integrity management regulations, for tank and station maintenance projects, for safety, training and related projects, for liability and property damage insurance, offset by lower costs for remote monitoring and control. Personnel and benefits costs increased $0.3 million primarily as a result of additions to the operations staff in Mississippi and costs associated with work vehicles for the new staff added $0.1 million. Costs associated with maintenance of right of ways and testing under pipeline integrity regulations increased a combined $0.1 million. In 2002, we increased safety training for our pipeline operations personnel at a cost of $0.1 million. Additionally we undertook a project to add Global Positioning Satellite information to our pipeline maps as required pursuant to pipeline safety regulations. Expenses incurred on this project in 2002 totaled $0.2 million. Insurance costs increased by $0.3 million due to the combination of insurance market conditions and our loss history. Our remote monitoring and control costs were lower by $0.1 million as we completed the transition in early 2002 from a more expensive service.
Outlook for 2004 and Beyond
After September 2004, we may continue to provide capacity to transport crude oil on our Texas System from Webster to Texas City and Houston. We expect to cease using the West Columbia to Webster segment and the Cullen Junction to Webster segment for crude oil service, as volumes shipped do not support the costs we would expect to incur to test and repair those segments of pipeline under the integrity management regulations. See discussion of the integrity management regulations in Safety Regulation under in "Item 1". If we continue to ship crude oil from Webster after September 2004, we would expect that we will receive it at Webster from new connections to other pipelines and receive less tariff income from those shipments than we are receiving under the current joint tariff with TEPPCO. We are also examining strategic opportunities to place the remaining segments in alternative service after the arrangement with TEPPCO expires.
We expect that volumes may decline in 2004 as refiners on the Texas Gulf Coast compete for crude oil with other markets connected to TEPPCO's pipeline systems; however, those effects may not occur until the summer of 2004 when TEPPCO finishes its integration and connection of the segments acquired from us.
As discussed above, the primary shipper on the segment of our Mississippi pipeline from Liberty to near Baton Rouge advised us in February 2004 that it does not have plans to reinstate shipments on this segment of pipeline. We currently plan to temporarily idle this segment of pipeline by removing the crude oil from the line while we evaluate future plans for this segment. Any future plans in crude oil service will require sufficient volumes being available to be transported on this segment of pipeline to justify the costs to perform the integrity testing and possible upgrading that may be necessary as a result of that testing. Future plans for this segment may include transportation of petroleum products or natural gas.
Denbury is the largest oil and gas producer in Mississippi. Our Mississippi pipeline is adjacent to several of Denbury's existing and prospective oil fields. There may be mutual benefits to Denbury and us due to this common production and transportation area. Because of this relationship, we may be able to obtain certain commitments for increased crude oil volumes, while Denbury may obtain the certainty of transportation for its oil production at competitive market rates. As Denbury continues to acquire and develop old oil fields using CO2 based tertiary recovery operations, Denbury would expect to add crude oil gathering and CO2 supply infrastructure
to these fields. Further, as the fields are developed over time, it may create increased demand for our crude oil transportation services.
The production shipped from oil fields surrounding our Jay system is a combination of new fields with estimated short production lives and older fields that have been producing for twenty to thirty years and are in the late stages of economic life. We believe that the highest and best use of the Jay system would be to convert it to natural gas service. We continue to review strategic alternatives with other parties in the region to explore this opportunity. This initiative is in a very preliminary stage. Part of the process will involve finding alternative methods for us to continue to provide crude oil transportation services in the area. While we believe this initiative has long-term potential, it is not expected to have a substantial impact on us during 2004 or 2005.
Pipeline segment margins from continuing operations should remain flat or decline slightly in 2004. We expect volume increases on the Mississippi system and the tariff increases on the Jay system to substantially offset increases in fixed costs, including the costs for testing under the integrity management program.
CARBON DIOXIDE (CO2) OPERATIONS
In November 2003, we acquired a volumetric production payment of 167.5 Bcf of CO2 from Denbury. Denbury owns 1.6 trillion cubic feet of estimated proved reserves of CO2 in the Jackson Dome area near Jackson, Mississippi. In addition to the production payment, Denbury also assigned to us three of their existing long-term CO2 contracts with industrial customers. Denbury owns the pipeline that is used to transport the CO2 to our customers as well as to its own tertiary recovery operations.
The industrial customers treat the CO2 and transport it to their own customers. The primary industrial applications of CO2 by these customers include beverage carbonation and food chilling and freezing. Based on Denbury's experience, we can expect some seasonality in our sales of CO2, as the dominant months for beverage carbonation and freezing food are from April to October, when warm weather drives up demand for beverages and the approaching holidays increase demand for frozen foods.
The average daily Mcf for each month in 2003, 2002 and 2001 purchased under these contracts was as follows:
The volumetric production payment entitles us to a maximum daily quantity of CO2 of 52,500 million cubic feet (Mcf) per day through December 31, 2009, 43,000 Mcf per day for the calendar years 2010 through 2012, and 25,000 Mcf per day beginning in 2013 until we have received all volumes under the production payment. Under the terms of a transportation agreement with Denbury, Denbury will process and deliver this CO2 to our industrial customers and receive a fee from us of $0.16 per Mcf, subject to inflationary adjustments, for those transportation services.
The terms of the contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. The maximum daily contract quantity per year in the contracts totals 48,750 Mcf. Under the minimum take or pay volumes, the customers must purchase a total of 14,468 Mcf per day whether received or not. Any volume purchased under the take-or-pay provision in any year can then be recovered in a future year as long as
the minimum requirement is met in that year. In the three years ended December 31, 2003, all three customers have purchased more than their minimum take-or-pay quantities, as can be seen in the table above.
The three industrial contracts extend through 2010, 2012 and 2015. The sales contracts contain provisions for inflationary adjustments to sales prices based on the Producer Price Index, with a minimum price.
During the two months we owned the CO2 assets in 2003, we earned revenues of $1.0 million and segment margin of $0.7 million. We expect to generate approximately $5 million of annual segment margin from this business during the first five years. The purchase of these assets provides us with diversity in our asset base and a stable long-term source of cash flow.
DISCONTINUED OPERATIONS
In the fourth quarter of 2003, we sold a significant portion of our Texas Pipeline System and the related crude oil gathering and marketing operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of Multifuels, Inc.. We received no proceeds from the sale to Blackhawk. Other remaining segments not sold to these parties were abandoned in place.
The sale of these assets was the result of an initiative started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce costs and risks of operation. As a result of this evaluation we determined that parts of our Texas Gulf Coast operations were of more strategic value to TEPPCO than to us. We also determined that other segments of the Texas Gulf Coast operations had little value and should be abandoned in place or sold to reduce costs or risks. By selling these assets, we eliminated approximately $6.6 million of capital expenditures that we might have had to make depending on the results of IMP testing.
TEPPCO paid us $21.6 million for the assets it acquired. We incurred transaction costs of $0.4 million which reduced the net proceeds to $21.2 million. TEPPCO also assumed responsibility for $0.6 million of unpaid royalties related to the crude oil purchase and sale contracts it assumed.
We entered into various agreements with TEPPCO including (a) a transitional services agreement whereby GELP will provide the use of certain assets that TEPPCO did not acquire and pipeline monitoring services at least through April 30, 2004, and (b) a joint tariff agreement whereby TEPPCO will invoice and collect and share with us the tariffs for transportation on the pipeline being sold and the segments we retained at least through October 31, 2004. We also agreed not to compete with TEPPCO in a 40-county area in Texas surrounding the pipeline for a five year period.
We retained responsibility for environmental matters related to the operations sold to TEPPCO for the period prior to the sale date, subject to certain conditions. TEPPCO will pay the first $25,000 for each environmental claim up to an aggregate of $100,000. We would be responsible for any environmental claim in excess of that amount up to an aggregate total of $2 million. TEPPCO has purchased an environmental insurance policy for amounts in excess of our $2 million responsibility and we reimbursed TEPPCO for one-half of the policy premium. Our responsibility to indemnify TEPPCO for environmental matters in connection with this transaction will cease in ten years. We do not expect the effects of this indemnification to have a material effect on our results of operations in the future.
During 2003, we recorded $0.4 million in termination benefits related to this sale. These benefits included retention bonuses and severance pay for employees affected by the sale.
Under the terms of the sale to Blackhawk, we agreed to provide transition services through March 31, 2004. These transition services are not significant as the pipeline is idle. We retained responsibility for any environmental matters related to the pipeline segments acquired by Blackhawk through December 31, 2003, however that responsibility will cease in ten years.
Operating results from the discontinued operations for the years ended December 31, 2003, 2002 and 2001 were as follows:
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
Revenues less crude costs and pipeline and field operating costs from discontinued operations in 2003 declined by $3.6 million, with $2.4 million of the decline resulting from crude oil gathering and marketing operations, and the remainder from pipeline operations.
Margin from discontinued crude oil gathering and marketing operations declined due to the following:
- an $0.8 million decrease in margin due to an decrease in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale;
- a 15 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a $1.4 million decrease in margin; and
- a $0.2 million increase in field operating costs from termination benefits.
Pipeline margin from discontinued operations decreased by $1.2 million due to the following:
- a 2 percent decrease in the average tariff on shipments resulting in a $0.1 million decrease in revenue;
- an 11 percent decrease in throughput between the two years, resulting in a $0.5 million revenue decrease; and
- a $1.0 million increase in pipeline operating costs in 2003. Included in the pipeline operating costs in 2003 is $0.7 million for demolition and disposal costs for tanks and other equipment that were not sold and no longer had any use to us. We chose to perform this demolition in 2003 to reduce the taxable gain that would be allocated to many of our unitholders from the sale to TEPPCO. Also included in 2003 is $0.2 million for termination benefits incurred as a result of the sale to TEPPCO. Other operating costs increased a total of $0.1 million.
These decreases were partially offset by a $0.4 million increase in revenues from sales of pipeline loss allowance barrels primarily as a result of higher crude oil market prices.
General and administrative expenses include the direct costs of individuals involved only with the assets sold. The decrease in these costs resulted from the termination of those persons from our employment as a result of the sale. The increase in depreciation in 2003 as compared to 2002 resulted from the elimination of the remaining book value of assets not sold that no longer had any use to us.
Year Ended December 31, 2002 Compared with Year Ended December 31, 2001
Revenues less crude costs and pipeline and field operating costs from discontinued operations in 2002 declined by $0.6 million. This amount is the net result of a $2.1 million decrease in margin from crude oil gathering and marketing operations, and a $1.5 million increase in margin from pipeline operations. Margin from crude oil gathering and marketing operations declined due to the following:
- a 22 percent decrease in wellhead, bulk and exchange purchase volumes between 2002 and 2003, resulting in a decrease in margin of $2.5 million; and
- $0.1 million increases in both field operating and credit costs.
Partially offsetting these decreases was a $0.6 million increase in margin due to a decrease in the average difference between the price of crude oil at the point of purchase and the price of crude oil at the point of sale.
Pipeline margin increased by $1.5 million due to the following:
- a 34 percent increase of in the average tariff on shipments resulting in a $1.4 million increase in revenue;
- a 10 percent increase in throughput between the two years, resulting in a $0.4 million revenue increase; and
- an increase in revenues from sales of pipeline loss allowance barrels of $0.7 million primarily as a result of higher crude oil market prices resulting in more revenue on these volumes.
Partially offsetting these increases was a $1.0 million increase in pipeline operating costs in 2002. These increases included a $0.2 million increase in costs associated with maintenance of right of ways and testing under pipeline integrity regulations; tank and station maintenance expenses increased $0.2 million and safety training for our pipeline operations personnel increased $0.2 million. Insurance costs increased $0.1 million and the mapping project added $0.3 million to costs.
In 2001, we recorded impairment of $35.5 related to the assets that were sold or abandoned in 2003. This impairment reduced the depreciation recorded in 2002.
OTHER COSTS AND INTEREST
Year Ended December 31, 2003 Compared with Year Ended December 31, 2002
General and administrative expenses. General and administrative expenses increased $0.9 million in 2003 from the 2002 level. Corporate governance costs including legal and consultant costs related to compliance with the Sarbanes-Oxley Act of 2002, increased directors fees and higher directors and officers insurance costs added $0.4 million. Other general and administrative costs increased by $0.1 million. Two other factors contributing to this increase were the write-off of $0.2 million of unamortized legal and consultant costs related to credit agreement with Citicorp and a non-cash charge of $0.2 million related to our new stock appreciation rights program for employees and directors (see Note 14 to the consolidated financial statements).
The write-off of unamortized costs was necessitated by the replacement of the Citicorp credit facility in 2003 with a credit facility with Fleet National Bank. Under our bonus program, bonuses were eliminated unless distributions were being paid, which resulted in no accrual in 2002.
We expect general and administrative expenses in 2004 to remain level with those of 2003. Consultant costs related to the internal documentation and assessment provisions of the Sarbanes-Oxley Act are expected to increase over 2003 levels, offsetting the 2003 write-off of credit facility costs.
Change in fair value of derivatives. We designated our contracts as normal purchases and sales under the provisions for that treatment in SFAS No. 133. We did not engage in any derivative transactions during 2003, and
would expect to do so in 2004 only as needed. During 2002, the fair value of the Partnership's net asset for derivatives decreased by $2.1 million.
Other operating charges. In 2002, we reached an agreement in principle with the federal and state regulatory authorities regarding the fines we would pay related to the spill that occurred in December 1999 in Mississippi. The cost to us under the agreement is expected to be $3.0 million. In the fourth quarter of 2001 we accrued $1.5 million for this potential fine and in the third quarter of 2002 another $1.5 million was accrued.
Interest expense, net. In 2003, our net interest expense decreased by $0.1 million. The primary factor was a decrease in March 2003 of the size of our credit facility from $80 million to $65 million. In 2002, the larger amount of the credit facility resulted in higher commitment fees.
Year Ended December 31, 2002 Compared with Year Ended December 31, 2001
General and administrative expenses. General and administrative expenses decreased $3.4 million in 2002 from the 2001 level. Changes in personnel costs primarily due to the elimination of bulk and exchange activities reduced general and administrative expenses $2.3 million, and charges from our bonus program were $0.8 million less in 2002. The remaining decrease of $0.3 million is attributable to decreases in expenses for legal, tax and other professional services, offset by small increases in administrative insurance costs and contract labor costs.
Depreciation, amortization and impairment. Depreciation and amortization expense decreased $1.7 million in 2002 from the 2001 level. As a result of the impairment of our pipeline assets in 2001, the value to be depreciated was reduced. The impairment recorded in 2001 was $9.6 million and related primarily to goodwill.
Change in fair value of derivatives. As a result of the significant reduction in our bulk and exchange activities at December 31, 2001, and a review of contracts existing at December 31, 2002, we determined that substantially all of our contracts did not meet the requirement for treatment as derivative contracts under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended and interpreted). The contracts were designated as normal purchases and sales under the provisions for that treatment in SFAS No. 133. As a result, the fair value of the Partnership's net asset for derivatives decreased by $2.1 million in 2002.
Net gain on disposal of surplus assets. In 2002, we disposed of our seats on the NYMEX for $1.7 million, resulting in a gain of $0.5 million. The changes we made in our business model to reduce our bulk and exchange activities eliminated our reasons for owning the NYMEX seats. Additionally, in 2002, we sold surplus land, a building and surplus vehicles, resulting in additional cumulative net gains of $0.2 million. In 2000, we leased our tractor/trailer fleet from Ryder Transportation Services. The majority of the existing fleet was sold in 2000 and 2001. Cash proceeds of $0.4 million and a gain of $0.1 million in 2001 were realized in 2001 from this sale.
Interest expense, net. In 2002, the Partnership had an increase in its net interest expense of $0.5 million. In 2001, the Partnership paid commitment fees on the unused portion of its $25 million facility with BNP Paribas. In the 2002 period, the Partnership paid commitment fees on the unused portion of its credit facility of $130 million in the first pat of the year and $80 million thereafter. The larger amount of the credit facility resulted in substantially higher commitment fees in 2002.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our primary sources of cash flows are operations, credit facilities, and in 2003, proceeds from the sale of a portion of our operations. Additionally in 2003, we issued limited partner interests to our general partner and received cash. Our primary uses of cash flows are capital expenditures and distributions. A summary of our cash flows for the years ended December 31, 2003, 2002 and 2001 is as follows (in thousands):
Operating. Net cash from operating activities for each year have been comprised of the following (in thousands):
Our operating cash flows are affected significantly by changes in items of working capital. We have had situations where other parties have prepaid for purchases or paid more than was due, resulting in fluctuations in one period as compared to the next until the party recovers the excess payment. While this happens infrequently, we did incorrectly receive $2.4 million in 2001 that was not repaid until 2003. During the 2001 period while we were actively engaged in bulk and exchange activities, our cash flows were affected by the differences in the timing between receiving the cash effects of derivative transactions and recording those transactions in net income. Affecting all periods is the timing of capital expenditures and their effects on our recorded liabilities.
Cash management in the crude oil gathering and marketing business functions as follows. All purchases and sales are settled monthly with payment on the 20th of the following month. We receive payment for sales by wire transfer on the 20th. Approximately 75% of the obligations for purchases are also paid by wire transfer on the 20th. The remaining 25% of purchases are paid for by check. These checks, primarily to royalty owners and small oil companies, generally take five or six days to clear our bank account. This payment cycle provides several benefits to us. We know that substantially all of our receivables for crude oil sales will be collected on the 20th. We also defer payment until checks that were mailed clear our checking accounts. Our borrowings, and therefore our interest costs, are reduced for this short time period each month following the 20th.
Similarly, tariffs are billed monthly and require payment ten days after the invoice date. Therefore collection of our pipeline accounts receivable is very rapid. Because shippers generally want to continue shipping, these receivables are generally paid quickly by our customers.
Our accounts receivable settle monthly and collection delays generally relate only to discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered. Of the $66.7 million aggregate receivables on our consolidated balance sheet at December 31, 2003, approximately $65.4 million, or 98.1%, were less than 30 days past the invoice date.
Investing. Cash flows used in investing activities in 2003 were $7.0 million as compared to $2.0 million in 2002. In 2003 we sold portions of our Texas pipeline system as well as other assets for $22.3 million net, and we expended $24.4 million to acquire the CO2 assets. Additionally we expended $4.9 million for other capital improvements. These expenditures included improvements on our Mississippi pipeline system to handle increased volumes more efficiently and effectively, additions and improvements totaling approximately $1.5 million on the Texas assets sold to TEPPCO in October 2003 and other equipment improvements.
In 2002 we expended $4.2 million for property and equipment additions. These expenditures included replacement of pipe in Mississippi and Texas and upgrades to pipeline stations in Mississippi to handle larger volumes of crude oil throughput, including building new tanks. Offsetting these expenditures in 2002, were sales of surplus assets from which we received $2.2 million. In early 2002, we sold our two seats on the NYMEX for $1.7 million as discussed above. We also received $0.5 million from the sale of excess land with a building.
In 2001, we expended $1.9 million for property and equipment, primarily in our pipeline operations. We received $0.5 million from the sale of tractors and trailers that were no longer needed as the fleet was replaced with new equipment leased from Ryder Transportation Inc. See additional detail on capital expenditures below.
Financing. In 2003, financing activities provided net cash of $4.1 million. In November 2003, our general partner acquired from us 688,811 newly-issued Common Units and a proportionate general partner interest for $5.0 million. We also increased our outstanding debt by $1.5 million. We utilized $1.1 million of these funds to pay
fees related to the new credit facility with Fleet National Bank. Distributions to our partners utilized $1.3 million. Net cash expended for financing activities was $10.2 million in 2002 as compared to $16.5 million in 2001. In 2002 we reduced long-term debt outstanding at year end by $8.4 million from the balance at December 31, 2001. We also paid a special distribution of $0.20 per unit in December 2002, which utilized $1.8 million of cash. In 2001, we reduced debt by $8.1 million from the balance at December 31, 2000, and paid four quarterly distributions in the amount of $0.20 per unit each, which utilized $7.0 million of cash.
Capital Expenditures
A summary of our capital expenditures in the three years ended December 31, 2003, 2002, and 2001 is as follows (in thousands):
Maintenance capital expenditures in 2003 included a total of $0.5 million for installation of pipeline satellite monitoring capabilities on all three systems. Administrative asset expenditures included computer hardware and software. In the first half of 2003, we continued to upgrade the West Columbia to Markham segment of our Texas pipeline. The expenditures on the Mississippi system included additional improvements to the pipeline from Soso to Gwinville, where the crude oil spill had occurred in December 1999, to restore this segment to service. We also improved the pipeline from Gwinville to Liberty to be able to handle increased volumes on that segment by upgrading pumps and meters and completing additional tankage.
Growth capital expenditures in 2003 included the acquisition of a condensate storage facility in Texas that was subsequently sold to TEPPCO and the acquisition of the CO2 assets from Denbury.
Although we have no commitments to make capital expenditures, based on the information available to us at this time, we currently anticipate that our capital expenditures will be as follows (in thousands):
In 2004, we expect the expenditures on our Texas system to relate primarily to corrosion control and in 2005 and 2006, to improvements to our control and monitoring system.
The maintenance capital expenditure estimates for our Mississippi system include corrosion control expenditures, minor facility improvements and rehabilitation of the pipeline as a result of integrity management test results, as discussed below.
Complying with Department of Transportation Pipeline Integrity Management Program (IMP) regulations has been and will be a significant driver in determining the amount and timing of our capital expenditure requirements. On March 31, 2001, the Department of Transportation promulgated the IMP regulations. The IMP regulations require that we perform baseline assessments of all pipelines that could affect High Consequence Areas (HCA). The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative technology. An HCA is defined as (a) a commercially navigable waterway; (b) an urbanized area that contains 50,000 or more people and has a density of at least 1,000 people per square mile; (c) other populated areas that contain a concentrated population, such as an incorporated or unincorporated city, town or village; and (d) an area of the environment that has been designated as unusually sensitive to oil spills. Due to the proximity of all of our pipelines to water crossings and populated areas, we have designated all of our pipelines as affecting HCAs. In accordance with the IMP regulations, we prepared a written Integrity Management Plan in 2002 that detailed our plans for testing and assessing each segment of the pipeline. The IMP regulations require that the baseline assessment be completed within seven years of March 31, 2002, with 50% of the mileage assessed in the first three and one-half years. Reassessment is then required every five years. We expect to spend $0.6 million in 2004 and $0.2 million in 2005 for pipeline integrity testing that will be charged to pipeline operating expense as incurred. As testing is completed, we are required to take prompt remedial action to address integrity issues raised by the assessment.
The rehabilitation action required as a result of the assessment and testing is expected to impact our capital expenditure program by requiring us to make improvements to our pipeline. This creates a difficult budgeting and planning challenge as we cannot predict the results of pipeline testing until they are completed. Based on estimated improvements required from assessments made during 2002 and 2003, we have estimated capital expenditures to be made during the IMP assessment period from 2004 through 2009. These capital expenditure projections are based on very preliminary data regarding the cost of rehabilitation. Such capital expenditure projections have been updated to eliminate the segments of the Texas system that were sold or abandoned in 2003, and the projections will be updated as improved data is obtained. During 2003 and 2002, $1.0 million and $1.7 million in capital expenditures were spent for rehabilitation of the Mississippi and Texas Pipeline Systems. Based on actual experience during 2003 and 2002 applied to our written IMP plan, we expect to spend $0.2 million, $1.2 million and $0.7 million in 2004, 2005 and 2006, respectively, for pipeline rehabilitation on the Mississippi System as a result of IMP testing. We currently do not expect to incur any rehabilitation expenditures on the other systems during this period.
Expenditures on capital assets to grow the partnership will depend on our access to debt and capital discussed below in "Sources of Future Capital." Our focus will be on acquisitions that add stable cash flows to smooth out the volatility of the crude oil gathering business. Those acquisitions may include the acquisition of additional CO2 assets from Denbury and the construction of CO2 and crude oil pipelines to access Denbury's crude oil fields in Mississippi. Denbury owns additional CO2 industrial sales contracts that we might be able to purchase along with additional volume under our production payment. We may also construct and operate CO2 pipelines next to crude oil pipelines to supply Denbury's fields with the CO2 for tertiary recovery and then to move the resulting crude oil production to market. We will also look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.
Capital Resources
In March 2003, we entered into a $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Facility"). The Fleet Facility also has a sublimit for working capital loans in the amount of $25 million, with the remainder of the facility available for letters of credit.
The key terms of the Fleet Facility are as follows:
- Letter of credit fees are based on the usage of the Fleet Facility in relation to the borrowing base and will range from 2.00% to 3.00%. At December 31, 2003, the rate was 2.00%.
- The interest rate on working capital borrowings is also based on the usage of the Fleet Facility in relation to the borrowing base. Loans may be based on the prime rate or the LIBOR rate, at our option. The interest rate on prime rate loans can range from the prime rate plus 1.00% to the prime rate plus 2.00%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.00% to the LIBOR rate plus 3.00%. At December 31, 2003, we borrowed at the prime rate plus 1.00%.
- We pay a commitment fee on the unused portion of the $65 million commitment. This commitment fee is also based on the usage of the Fleet Facility in relation to the borrowing base and will range from 0.375% to 0.50%. At December 31, 2003, the commitment fee rate was 0.375%.
- The amount that we may have outstanding cumulatively in working capital borrowings and letters of credit is subject to a Borrowing Base calculation. The Borrowing Base is defined in the Fleet Facility generally to include cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly.
- Collateral under the Fleet Facility consists of our accounts receivable, inventory, cash accounts, margin accounts and fixed assets.
- The Fleet Facility contains covenants requiring a minimum current ratio, a minimum leverage ratio, a minimum cash flow coverage ratio, a maximum ratio of indebtedness to capitalization, a minimum EBITDA (earnings before interest, taxes, depreciation and amortization), and limitations on distributions to Unitholders.
We were in compliance with the Fleet Facility covenants at December 31, 2003.
Under the Fleet Facility, distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage by certain amounts. See additional discussion below under "Distributions".
At December 31, 2003, we had $7.0 million outstanding under the Fleet Facility. Due to the revolving nature of loans under the Fleet Facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of March 14, 2006. At December 31, 2003, we had letters of credit outstanding under the Fleet Facility totaling $21.6 million, comprised of $10.0 million and $10.8 million for crude oil purchases related to December 2003 and January 2004, respectively and $0.8 million related to other business obligations. Outstanding letters of credit issued to Denbury for the purchase of crude oil at December 31, 2003, totaled $12.5 million, and are included in the $21.6 million total above. In February 2004, Denbury agreed to reduce by half its requirement to provide Denbury with letters of credit for our crude oil purchases from them.
Sources of Future Capital
Prior to 2003, we funded our capital commitments from operating cash and borrowings under bank facilities. In 2003, we issued common units to our general partner for cash and sold assets to fund growth. Our plans for the future include a combination of borrowings and the issuance of additional common units to the public.
We have entered into discussions with Fleet National Bank regarding an expansion of our existing credit facility from $65 million to $100 million. We would like to reduce the amount of the facility committed to letters of credit and working capital borrowings from $65 million to $50 million and have $50 million available for acquisitions. We are in discussions with Fleet to determine the terms of the expanded facility.
We may consider raising capital through an equity offering of additional common units if we make acquisitions using an expanded credit facility. Any such proceeds could be used to reduce the outstanding balances under the credit facility thereby freeing up debt capacity to use for additional accretive acquisitions. An equity offering would probably not occur before the fourth quarter of 2004.
Distributions
As a master limited partnership, the key consideration of our Unitholders is the amount of our distribution, its reliability and the prospects for distribution growth. Normally we distribute 100% of our Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. The target minimum quarterly distribution ("MQD") for each quarter is $0.20 per unit. For 2001, we paid distributions of $0.20 per unit ($1.8 million in total) per quarter for the first three quarters. For the fourth quarter of 2001 and for all of 2002, we did not pay any regular quarterly distributions. We did pay a special distribution of $0.20 per unit ($1.7 million in total) in December 2002 to help mitigate the tax effects of income allocations for that year. Beginning with the distribution for the first quarter of 2003, we paid a regular quarterly distribution of $0.05 per unit ($0.4 million in total per quarter). For the fourth quarter of 2003, we increased our quarterly distribution to $0.15 per unit ($1.4 in total), which was paid in February 2004.
Under the Fleet Agreement, a provision requires that the Borrowing Base exceed the usage under the Fleet Agreement by at least $10 million plus the distribution measured once each month in order for us to make a distribution for the quarter.
Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner generally is entitled to receive 13.3% of any distributions in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit without duplication. We have not paid any incentive distributions through December 31, 2003. The likelihood and timing of the payment of any incentive distributions will depend on our ability to make accretive acquisitions and generate cash flows from of those acquisitions. We do not expect to make incentive distributions during 2004.
We believe we will be able to sustain a regular quarterly distribution at $0.15 per unit during 2004. We do not expect to be able to restore the distribution to the targeted minimum quarterly distribution level of $0.20 per unit until 2005. However, if we exceed our expectations for improving the performance of the business, if our capital projects cost less than we currently estimate, or if our access to capital allows us to make accretive acquisitions, we may be able to restore the targeted minimum quarterly distribution sooner.
Available Cash before reserves for the year ended December 31, 2003, is as follows (in thousands):
Available Cash (a non-GAAP liquidity measure) has been reconciled to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2003 below.
The non-GAAP financial measure of Available Cash is calculated in accordance with generally accepted accounting principles (GAAP), with the exception of maintenance capital expenditures as used in our calculation of Available Cash. Maintenance capital expenditures are capital expenditures (as defined by GAAP) to replace or enhance partially or fully depreciated assets in order to sustain the existing operating capacity or efficiency of our assets and extend their useful lives.
We believe that investors benefit from having access to the same financial measures being utilized by management. Available Cash is a liquidity measure used by our management to compare cash flows generated by the Partnership to the cash distribution we pay to our limited partners and the general partner. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment. Specifically, this financial measure tells investors whether or not the Partnership is generating cash flows at a level that can support a quarterly cash distribution to our partners. Lastly, Available Cash (also referred to as distributable cash flow) is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships.
Several adjustments to net income are required to calculate Available Cash. These adjustments include: (1) the addition of non-cash expenses such as depreciation and amortization expense; (2) miscellaneous non-cash adjustments such as the addition of decreases or the subtraction of increases in the value of financial instruments; and (3) the subtraction of maintenance capital expenditures. See "Distributions" above.
The reconciliation of Available Cash (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2003, is as follows (in thousands):
COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS
Contractual Obligation and Commercial Commitments
In addition to the Fleet Facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil. The table below summarizes our obligations and commitments at December 31, 2003 (in thousands).
In December 2003, our insurers settled litigation with Pennzoil-Quaker State for $12.8 million. (see Note 18 to the consolidated financial statements.) We have recorded in accrued liabilities on our consolidated statement of operations the obligation for this settlement, and we have recorded the insurance reimbursement for this obligation in insurance receivable. The settlement was funded in February 2004, with certain insurance companies directly funding $5.9 million of the payment and with our funding the remaining $6.9 million. We expect to receive reimbursement from the insurance company no later than May 2004.
We expect to pay the estimated $3.0 million fine related to the Mississippi oil spill that occurred in 1999 (see Note 18 to the consolidated financial statements) during the second quarter of 2004. We expect to incur approximately $0.7 million to remove an abandoned offshore pipeline during the second quarter of 2004.
While the temporary funding of the litigation settlement and the payment of the fine and pipeline removal costs will increase our average outstanding debt during 2004, we believe we have sufficient capacity under the Fleet Facility to meet these obligations.
Off-Balance sheet Arrangements
We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed in this section, nor do we have any debt or equity triggers based upon our unit or commodity prices.
OTHER MATTERS
Risk Factors Related to Our Business
The success of our crude oil gathering, marketing and pipeline operations is dependent upon increases in the availability of crude oil supplies and our ability to secure those supplies. Securing additional supplies of crude oil from increased production by oil companies and by aggressive lease gathering efforts depends partially on the ability of oil producers to increase production. Factors affecting an increase in production can include the prevailing market price for oil, the exploration and production budgets of the major and independent oil companies, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives and other matters that are beyond our control.
The profitability of our crude oil gathering and marketing operations depends primarily on the volumes of crude oil we purchase and gather. Natural declines in crude oil production from depleting wells or volumes lost to competitors must be replaced by contracts for new supplies of crude oil so as to maintain the volumes of crude oil we purchase. Replacement of lost volumes of crude oil is particularly difficult in an environment where production is low and competition to gather available production is intense. Generally, because producers experience inconveniences in switching crude oil purchasers, such as delays in receipt of proceeds while awaiting the preparation of new division orders, producers typically do not change purchasers on the basis of minor variations in price. Thus, we may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationships between producers and other gatherers and purchasers of crude oil.
Our operations are dependent upon demand for crude oil by refiners in the Gulf Coast and Midwest. Any decrease in this demand could adversely affect our business. This demand is dependent on the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand.
We face intense competition in our crude oil gathering and marketing activities. Our competitors include independent gatherers, the major integrated oil companies and their marketing affiliates and other marketers of various sizes, financial resources and experience. Many of these competitors have capital resources many times greater than ours and control much greater supplies of crude oil.
We are exposed to the credit risk of our customers in the ordinary course of our crude oil gathering and marketing operations. There can be no assurance that we have adequately assessed the credit worthiness of our existing or future counter-parties or that there will not be an unanticipated deterioration in their credit worthiness, which could have an adverse impact on us. In those cases where we provide division order services for crude oil purchased at the wellhead, we may be responsible for the distribution of proceeds to all parties. In other cases, we pay all or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk, and there can be no assurance that we will not experience losses in dealings with other parties.
The profitability of our crude oil pipeline operations depends on the volume of crude oil shipped by third parties and on our interconnections with other crude oil pipelines. Third-party shippers do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. Additionally, in Mississippi, we are dependent on interconnections with other pipelines to provide shippers with a market for their crude oil, and in Texas, we are dependent on interconnections with other pipelines to provide shippers with transportation to our pipeline. Any reduction of throughput available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or other causes could result in reduced throughput on our pipelines that would adversely affect our profitability.
Fluctuations in demand for crude oil, such as caused by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our pipelines can result in less demand for our transmission services.
Our operations are subject to federal and state environmental and safety regulations and laws related to environmental protection and operational safety. Our crude oil gathering and pipeline operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or
claims for damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through greater margins, higher tariffs or insurance reimbursements; our cash flows and results of operations could be materially impacted. The transportation and storage of crude oil results in a risk that crude oil and related hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages, and significant business interruption.
Certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes gathered by truck or transmitted by our pipelines. As a result, we may experience declines in segment margin and profitability should our volumes decrease.
Our CO2 operations are exposed to risks related to Denbury's operation of their CO2 fields, equipment and pipeline. Because Denbury produces the CO2 and transports the CO2 to our customers, any long-term failure of their operations could have an impact on our ability to meet our obligations to our CO2 customers. We have no other supply of CO2 or method to transport it to our customers.
Fluctuations in demand for CO2 by our industrial customers could materially impact our profitability. Our customers are not contractually obligated to purchase volumes in excess of the take-or-pay amounts in the contracts. The customers have processing facilities located at the delivery points on Denbury's pipeline. Fluctuations in their demand due to market forces or operational problems could result in a reduction in our revenues from the sales of CO2.
The CO2 supplied by Denbury to us for our sale to our customers could fail to meet the quality standards in the contracts due to impurities or water vapor content. If the CO2 were below specifications, we could be contractually obligated to provide compensation to our customers for the costs incurred in raising the CO2 quality to serviceable levels.
Our wholesale CO2 industrial marketing operations are dependent on three customers. Should one or more of those customers experience financial difficulties such that they fail to purchase their required minimum take-or-pay volume and fail to compensate us for the lost revenue, our profitability could be materially impacted. The three customers appear to be credit worthy, however there can be no assurance that an unanticipated deterioration in their ability to meet their obligations to us might not occur.
Newly acquired properties could expose us to environmental liabilities and increased regulatory compliance costs. Our business plan includes making acquisitions to increase our cash flows. Assets that we may acquire will likely have associated environmental liabilities, as well as required compliance with regulations such as the integrity management program for regulated pipelines. Although we will attempt to identify such exposures and address the associated costs through indemnities, purchase price adjustments or insurance, we may incur costs not covered by indemnity, insurance or reserves.
Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of reserves. Because distributions to our unitholders are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made in periods when we record losses and might not be made during periods when we record profits.
The terms of our credit facility may limit our ability to borrow additional funds, make distributions to unitholders, or capitalize on business opportunities. Our credit facility includes limitations on our ability to make distributions to our unitholders and require approval of lenders to take certain actions. Any refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it could substantially reduce distributions to our unitholders and might reduce
our ability to grow the business. The after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal and state income tax purposes. If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate rate. Some or all of the distributions made to unitholders would be treated as dividend income, and no income, gains, losses or deductions would flow through to unitholders. Treatment of us as a corporation would cause a material reduction in the anticipated cash flow and after-tax return to the unitholders.
We believe a substantial number of our Common Units are held by entities that derive a tax benefit from investment in partnership-type entities with large gross receipts. Should a change occur such that our revenues declined to a level that these investors might find alternative sources for this tax benefit other than by ownership in our Common Units, an adverse change in our unit price could take place. This condition could occur at the same time that we would be growing our distribution or otherwise increasing the value of our Common Units to the general investing public.
Crude Oil Contamination
We were named one of the defendants in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, cause No. 2001-01176. Pennzoil-Quaker State Company ("PQS") was seeking property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. In December 2003, our insurers settled this litigation for $12.8 million. We have recorded in accrued liabilities on our consolidated balance sheet the obligation for this settlement, and, in insurance receivable, we have recorded the insurance reimbursement for this obligation. The settlement was funded in February 2004, with certain insurance companies directly funding $5.9 million of the payment and $6.9 million funded by us. We expect to receive reimbursement from the insurance company no later than May 2004 for the portion funded by us. The settlement of this litigation had no effect on our results of operations.
PQS is also a defendant in five suits brought by neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial District Court, Caddo Parish, Louisiana, cause nos. 455,647-A. 455,658-B, 455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against Genesis and others for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against Genesis is without merit and intend to vigorously defend ourselves in this matter.
Insurance
We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance policies are subject to deductibles that we consider reasonable. The policies do not cover every potential risk associated with operating our assets, including the potential for a loss of significant revenues. Consistent with the coverage available in the industry, our policies provide limited pollution coverage, with broader coverage for sudden and accidental pollution events. Additionally, as a result of the events of September 11, the cost of insurance available to the industry has risen significantly, and insurers have excluded or reduced coverage for losses due to acts of terrorism and sabotage.
Since September 11, 2001, warnings have been issued by various agencies of the United States Government to advise owners and operators of energy assets that those assets may be a future target of terrorist organizations. Any future terrorist attacks on our assets, or assets of our customers or competitors could have a material adverse effect on our business.
We believe that we are adequately insured for public liability and property damage to others as a result of our operations. However, no assurances can be given that an event not fully insured or indemnified against will not materially and adversely affect our operations and financial condition. Additionally, no assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable.
NEW ACCOUNTING PRONOUNCEMENTS
SFAS 143
In June, 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. The standard was effective for us on January 1, 2003.
With respect to our pipelines, federal regulations require us to purge the crude oil from our pipelines when the pipelines are retired. Our right of way agreements do not require us to remove pipe or otherwise perform remediation upon taking the pipelines out of service. Many of our truck unload stations are on leased sites that require that we remove our improvements upon expiration of the lease term. For our pipelines, we are unable to reasonably estimate and record liabilities for the majority of our obligations that fall under the provisions of this statement because we cannot reasonably estimate when such obligations would be settled. For the truck unload stations, the site leases have provisions such that the lease continues until one of the parties gives notice that it wishes to end the lease. At this time we cannot reasonably estimate when such notice would be given and when the obligations to remove our improvements would be settled. We will record asset retirement obligations in the period in which we determine the settlement dates.
In the third quarter of 2003, we recorded an obligation to remove a pipeline from offshore waters as a result of this standard. This pipeline has been out of service since 1998. The State of Louisiana advised us that the pipeline should be removed. We expect to remove this pipeline during 2004.
SFAS 145
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No. 145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions related to the rescission of SFAS No. 4 were applied in fiscal years beginning after May 15, 2002. The provisions related to SFAS No. 13 were effective for transactions occurring after May 15, 2002. All other provisions were effective for financial statements issued on or after May 15, 2002, with early application encouraged. The adoption of this statement did not have a material effect on our results of operations.
SFAS 146
On January 1, 2003, we adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. This statement requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred rather than at the date of commitment to an exit plan. This adoption of this statement on January 1, 2003, had no material impact on our financial statements. During the third quarter of 2003, we recorded termination benefits related to the sale of our Texas Gulf Coast operations and, in the fourth quarter of 2003, recorded the sale of those operations. See Note 11 to the consolidated financial statements.
Interpretation No. 45
We implemented FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The information required by this interpretation is included in Note 18 to the consolidated financial statements.
Interpretation No 46
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," and amended the Interpretation in December 2003. The interpretation states that certain variable interest entities (VIE) may be required to be consolidated into the results of operations and financial position of the entity that is the primary beneficiary. The provisions of the interpretation were effective immediately for VIEs created after January 15, 2003. We do not have any VIEs. The adoption of this interpretation in 2003 had no effect on our financial statements.
SFAS 148
We adopted SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as of January 1, 2003. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. As there are no outstanding grants of Partnership units under any compensation plans of the Partnership, the adoption of this statement had no effect on our financial position, results of operations, cash flows or disclosure requirements.
SFAS 149
On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows.
SFAS 150
In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain freestanding instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). We adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary price risk relates to the effect of crude oil price fluctuations on our inventories and the fluctuations each month in grade and location differentials and their effect on future contractual commitments. We utilize NYMEX commodity based futures contracts and forward contracts to hedge our exposure to these market price fluctuations as needed. At December 31, 2003, we had no contracts outstanding.
At December 31, 2003, we held 49,000 barrels of crude oil in inventory with a carrying cost of $1.5 million. The market value of this inventory at December 31, 2003 was $30,000 greater than its cost.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set forth in the "Index to Consolidated Financial Statements" on page 52.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our chief executive officer and chief financial officer have evaluated our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K and have determined that such disclosure
controls and procedures are adequate and effective in all material respects in providing to them on a timely basis material information relating to us (including our consolidated subsidiaries) required to be disclosed in this annual report.
There have been no significant changes in our internal controls over financial reporting during the three months ended December 31, 2003, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
We do not directly employ any persons responsible for managing or operating the Partnership or for providing services relating to day-to-day business affairs. The General Partner provides such services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs.
The Board of Directors of the General Partner (the "Board") consists of eight persons. Four of the directors, including the Chairman of the Board, are executives of Denbury. Our Chief Executive Officer serves on the Board. The three remaining directors are independent of Genesis and Denbury or any of its affiliates.
Directors and Executive Officers of the General Partner
Set forth below is certain information concerning the directors and executive officers of the General Partner. All executive officers serve at the discretion of the General Partner.
Gareth Roberts has served as a Director and Chairman of the Board of the General Partner since May 2002. Mr. Roberts is President, Chief Executive Officer and a director of Denbury Resources Inc. and has served in those capacities since 1992. Mr. Roberts also serves on the board of directors of Belden & Blake Corporation.
Mark J. Gorman has served as a Director of the General Partner since December 1996 and as President and Chief Executive Officer since October 1999. From December 1996 to October 1999 he served as Executive Vice President and as Chief Operating Officer from October 1997 to October 1999. He was President of Howell Crude Oil Company, a wholly-owned subsidiary of Howell Corporation, from September 1992 to December 1996.
Ronald T. Evans has served as a director of the General Partner since May 2002. Mr. Evans is Senior Vice President of Reservoir Engineering of Denbury and has served in that capacity since September 1999. Before joining Denbury, Mr. Evans was employed as Engineering Manager with Matador Petroleum Corporation for three years and employed by Enserch Exploration, Inc. for twelve years in various positions.
Herbert I. Goodman has served as a director of the General Partner since January 1997. He is the Chairman of IQ Holdings, Inc., a manufacturer and marketer of petrochemical-based consumer products. During 2001, he served as the Chief Executive Officer of PEPEX.NET, LLC, which provides electronic trading solutions to the international oil industry. Since 2002 he has served as Chairman of PEPEX.NET, LLC. From 1988 until 1996 he was Chairman and Chief Executive Officer of Applied Trading Systems, Inc., a trading and consulting business.
Susan O. Rheney became a Director of the General Partner in March 2002. Ms. Rheney is a private investor and formerly was a principal of The Sterling Group, L.P., a private financial and investment organization, from 1992 to 2000. Ms. Rheney is a director of Texas Petrochemical Holdings, Inc., a chemical manufacturer, where she serves on the audit and finance committees. She is also a director of Mail-Well, Inc., a supplier of printing services and products, where she serves on the audit and governance and nominating committees.
Phil Rykhoek has served as a director of the General Partner since May 2002. Mr. Rykhoek is Chief Financial Officer, Senior Vice President, Secretary and Treasurer of Denbury, and has served in those capacities since 1995.
J. Conley Stone has served as a director of the General Partner since January 1997. From 1987 to his retirement in 1995, he served as President, Chief Executive Officer, Chief Operating Officer and Director of Plantation Pipe Line Company, a common carrier liquid petroleum products pipeline transporter.
Mark A. Worthey has served as a director of the General Partner since May 2002. Mr. Worthey is Senior Vice President, Operations for Denbury and has been with Denbury since September 1992.
Ross A. Benavides has served as Chief Financial Officer of the General Partner since October 1998. He has served as General Counsel and Secretary since December 1999.
Kerry W. Mazoch has served as Vice President, Crude Oil Acquisitions, of the General Partner since August 1997. From 1991 to 1997 he held the position of Vice President and General Manager of Crude Oil Acquisitions at Northridge Energy Marketing Corp., a wholly-owned subsidiary of TransCanada Pipelines Limited.
Karen N. Pape was named Vice President and Controller of the General Partner effective in March 2002. Ms. Pape has served as Controller and as Director of Finance and Administration of the General Partner since December 1996. From 1990 to 1996, she was Vice President and Controller of Howell Corporation.
Board Committees
The Audit Committee consists of Susan O. Rheney, Herbert I. Goodman and J. Conley Stone. The Audit Committee has been established in accordance with SEC rules and regulations, and all members are independent directors as defined under the rules of the American Stock Exchange. The Board of Directors believes that Susan O. Rheney qualifies as an audit committee financial expert as such term is used in the rules and regulations of the SEC. The committee engages our independent auditors and oversees our independence from the auditors, pre-approves any services provided by our independent auditors, oversees the quality and integrity of our financial reports and our systems of internal controls with respect to finance, accounting, legal compliance and ethics, and oversees our anonymous complaint procedure established for our employees. The Audit Committee adopted a written Audit Committee charter on August 7, 2003. The full text of the Audit Committee charter is available on our website.
Additionally, the General Partner is authorized to seek special approval from the Audit Committee of any resolution of a potential conflict of interest between the General Partner or of any of its affiliates and the Partnership or any of its affiliates.
The Board has established a compensation committee to oversee compensation decisions for the employees of the General Partner, as well as the compensation plans of the General Partner. The members of the Compensation Committee are Gareth Roberts, Susan O. Rheney and Herbert I. Goodman, all of whom are non-employee directors of the General Partner.
Code of Ethics
We have adopted a code of ethics that is applicable to, among others, the principal financial officer and the principal accounting officer. The Genesis Energy Financial Employee Code of Professional Conduct is posted at our website, where we intend to report any changes or waivers.
Section 16(a) Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the officers and directors of the General Partner and persons who own more than ten percent of a registered class of the equity securities of the Partnership to file reports of ownership and changes in ownership with the SEC and the American Stock Exchange. Based solely on its review of the copies of such reports received by it, or written representations from certain reporting persons that
no Forms 5 was required for those persons, we believe that during 2003 its officers and directors complied with all applicable filing requirements in a timely manner.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE OFFICER COMPENSATION
Under the terms of the Partnership Agreement, we are required to reimburse the General Partner for expenses relating to the operation of the Partnership, including salaries and bonuses of employees employed on behalf of the Partnership, as well as the costs of providing benefits to such persons under employee benefit plans and for the costs of health and life insurance. See "Certain Relationships and Related Transactions."
Summary Compensation Table
The following table summarizes certain information regarding the compensation paid or accrued by Genesis during 2003, 2002, and 2001 to the Chief Executive Officer and each of our three other executive officers (the "Named Officers").
(1) Represents the value deemed to have been "earned" during the year under the Stock Appreciation Rights Plan discussed below. No Named Officer had other "Perquisites and Other Personal Benefits" with a value greater than the lesser of $50,000 or 10% of reported salary and bonus.
(2) SARs are Stock Appreciation Rights. See additional information in the table below.
(3) Includes $9,000 of Company-matching contributions to a defined contribution plan and $6,000 of profit-sharing contributions to a defined contribution plan.
(4) Includes $5,500 of Company-matching contributions to a defined contribution plan and $6,000 of profit-sharing contributions to a defined contribution plan.
(5) Includes $5,100 of Company-matching contributions to a defined contribution plan and $5,100 of profit-sharing contributions to a defined contribution plan.
(6) Includes $8,282 of Company-matching contributions to a defined contribution plan and $5,521 of profit-sharing contributions to a defined contribution plan.
(7) Includes $7,802 of Company-matching contributions to a defined contribution plan and $5,521 of profit-sharing contributions to a defined contribution plan
(8) Includes $5,500 of Company-matching contributions to a defined contribution plan and $5,978 of profit-sharing contributions to a defined contribution plan.
(9) Includes $6,320 of Company matching contributions to a defined contribution plan and $4,213 of profit-sharing contributions to a defined contribution plan.
(10) Includes $5,059 of Company-matching contributions to a defined contribution plan and $5,059 of profit-sharing contributions to a defined contribution plan.
Stock Appreciation Rights Plan
In December 2003, the Board approved a Stock Appreciation Rights plan for all employees. Under the terms of this plan, all regular, full-time active employees and the members of the Board are eligible to participate in the plan. The plan is administered by the Compensation Committee of the Board, who shall determine, in its full discretion, the number of rights to award, the grant date of the units and the formula for allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one Common Unit. The rights have a term of 10 years from the date of grant. The initial award to a participant will vest one-fourth each year beginning with the first anniversary of the grant date of the award. Subsequent awards to participants will vest on the fourth anniversary of the grant date. If the right has not been exercised at the end of the ten year term and the participant has not terminated employment with us, the right will be deemed exercised as of the date of the right's expiration and a cash payment will be made as described below.
Upon vesting, the participant may exercise his rights to receive a cash payment equal to the difference between the average of the closing market price of Genesis Energy, L.P. Common Units for the ten days preceding the date of exercise over the strike price of the right being exercised. The cash payment to the participant will be net of any applicable withholding taxes required by law. If the Committee determines, in its full discretion, that it would cause significant financial harm to the Partnership to make cash payments to participants who have exercised rights under the plan, then the Committee may authorize deferral of the cash payments until a later date.
Termination for any reason other than death, disability or normal retirement (as these terms are defined in the plan) will result in the forfeiture of any non-vested rights. Upon death, disability or normal retirement, all rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change in control (as defined in the plan) all rights will become fully vested.
On December 31, 2003, the initial award of rights was made to employees and directors. The following tables show the stock appreciation rights granted to the Executive Officers and the values of the stock appreciation rights at December 31, 2003. Information on rights granted to non-employee directors is included in the section entitled Director Compensation.
SAR Grants During the Year Ended December 31, 2003
December 31, 2003 SAR Values
Bonus Plan
In May 2003, the Compensation Committee of the Board of the General Partner approved a Bonus Plan (the "Bonus Plan") for all employees of the General Partner. The Bonus Plan is designed to enhance the financial performance of the Partnership by rewarding employees for achieving financial performance objectives. The Bonus Plan is administered by the Compensation Committee. Under this plan, amounts will be allocated for the payment of bonuses to employees each time GCOLP earns $1.6 million of Available Cash. The amount allocated to the bonus pool increases for each $1.6 million earned, such that a maximum bonus pool of $2.0 million will exist if the Partnership earns $14.6 million of Available Cash.
Bonuses will be paid to employees after the end of the year. The amount in the bonus pool will be allocated to employees based on the group to which they are assigned. Employees in the first group can receive bonuses that range from zero to ten percent of base compensation. The next group includes employees in the professional group, who could earn a total bonus ranging from zero to twenty percent. Certain members of the professional group that are part of management or are exceptional performers are eligible to earn a total bonus ranging from zero to thirty percent. Lastly, our officers and other senior management are eligible for a total bonus ranging from zero to forty percent. The Bonus Plan will be at the discretion of the Compensation Committee, and the General Partner can amend or change the Bonus Plan at any time.
DIRECTOR COMPENSATION
Information regarding the compensation received from the General Partner by Mr. Gorman, President, Chief Executive Officer and a director of the General Partner, is disclosed under the heading "Executive Officer Compensation".
Directors Fees
The three independent directors receive an annual fee of $30,000. The Audit Committee Chairman receives an additional annual fee of $4,000 and all members of the Audit Committee receive $1,500 for attendance at each committee meeting. Denbury receives $120,000 from the Partnership for providing four of its executives as directors. Mr. Gorman does not receive a fee for serving as a director.
Stock Appreciation Rights
The non-employee directors received stock appreciation rights under the same terms as the Executive Officers. Grants issued to directors during 2003 were:
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Beneficial Ownership of Partnership Units
The following table sets forth certain information as of February 28, 2004, regarding the beneficial ownership of our units by beneficial owners of 5% or more of the units, by directors and the executive officers of our general partner and by all directors and executive officers as a group. This information is based on data furnished by the persons named.
---------- * Less than 1%
Each unitholder in the above table is believed to have sole voting and investment power with respect to the shares beneficially held. Included in the units held by Mark A Worthey are 500 units held for a minor child. Included in the units held by Kerry W. Mazoch are 584 units held with his children.
Beneficial Ownership of General Partner Interest
Genesis Energy, Inc. owns all of our 2% general partner interest and all of our incentive distribution rights, in addition to 7.4% of our units. Genesis Energy, Inc. is a wholly-owned subsidiary of Denbury Resources, Inc.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Our General Partner
Our operations are managed by, and our employees are employed by, Genesis Energy, Inc., our general partner. Our general partner does not receive any management fee or other compensation in connection with the management of our business, but is reimbursed for all direct and indirect expenses incurred on our behalf. During 2003, these reimbursements totaled $16.0 million. At December 31, 2003, we owed the general partner $0.1 million related to these services.
Our general partner owns the 2% general partner interest and all incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13.3% of amounts we distribute in excess of $0.25 per unit, 23.5% of the amounts we distribute in excess of $0.28 per unit, and 49% of the amounts we distribute in excess of $0.33 per unit.
Relationship with Denbury Resources, Inc.
Through its control of our general partner, Denbury has the ability to control our management. During 2003, we acquired a CO2 volumetric production payment and related wholesale marketing contracts from Denbury for $24.4 million. Additionally we enter into transactions with Denbury in the ordinary course of its operations. During 2003, these transactions included:
- Purchases of crude oil from Denbury totaling $59.7 million. We provide letter of credit to Denbury related to these purchases.
- Provision of CO2 transportation services to our wholesale industrial customers by Denbury's pipeline. The fees for this service totaled $0.4 million in 2003.
- Provision of services by Denbury officers as directors of our general partner. We paid Denbury $120,000 for these services in 2003.
At December 31, 2003, we owed Denbury $6.9 million for purchases of crude oil and $0.1 million for transportation services.
In 2002, we amended our partnership agreement to broaden the right of the Common Unitholders to remove the General Partner. Prior to this amendment, the general partner could only be removed for cause and with approval by holders of two-thirds or more of the outstanding limited partner interests in GELP. As amended, the partnership agreement provides that, with the approval of at least a majority of the limited partners in GELP, the general partner also may be removed without cause. Any limited partner interests held by the general partner and its affiliates would be excluded from such a vote.
The amendment further provides that if it is proposed that the removal is without cause and an affiliate of Denbury is the general partner to be removed and not proposed as a successor, then any action for removal must also provide for Denbury to be granted an option effective upon its removal to purchase GELP's Mississippi pipeline system at a price that is 110 percent of its fair market value at that time. Fair value is to be determined by agreement of two independent appraisers, one chosen by the successor general partner and the other by Denbury or if they are unable to agree, the mid-point of the values determined by them.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table summarizes the aggregate fees billed to us by Deloitte & Touche LLP.
(a) Fees for audit services billed in 2003 consisted of:
Audit of our annual financial statements Audit of our General Partner financial statements Reviews of our quarterly financial statements Financial statement audits of prior years that were originally audited by Arthur Andersen LLP.
Fees for audit services billed in 2002 consisted of:
Audit of our annual financial statements Reviews of our quarterly financial statements.
(b) Fees for audit-related services in 2003 and 2002 consisted of: Financial accounting and reporting consultations Sarbanes-Oxley Act, Section 404 advisory services Employee benefit plan audits.
Deloitte provided no tax services or other services to us in 2002 or 2003. In considering the nature of the services provided by Deloitte, the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with Deloitte and management of our General Partner to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants.
Pre-Approval Policy
The services by Deloitte in 2003 were pre-approved in accordance with the pre-approval policy and procedures adopted by the Audit Committee at its May 9, 2003 meeting. This policy describes the permitted audit, audit-related, tax and other services (collectively, the "Disclosure Categories") that the independent auditor may perform. The policy requires that prior to the beginning of each fiscal year, a description of the services (the "Service List") expected to be performed by the independent auditor in each of the Disclosure Categories in the following fiscal year be presented to the Audit Committee for approval.
Services provided by the independent auditor during the following year that are included in the Service List were pre-approved following the policies and procedures of the Audit Committee.
Any requests for audit, audit-related, tax and other services not contemplated on the Service List must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meeting.
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Consolidated Financial Statements" set forth on page 52.
(a)(3) Exhibits
---------- * Filed herewith
+ A management contract or compensation plan or arrangement.
(b) Reports on Form 8-K
A Current Report on Form 8-K was filed on November 24, 2003, in connection with the purchase of a volumetric production payment from Denbury.
A Current Report on Form 8-K was furnished on November 11, 2003, providing, under Items 7, 9 and 12, the Partnership's news release including attached schedules dated November 11, 2003, that announced the Partnership's financial and operating results for the three and nine month periods ended September 30, 2003.
A Current Report on Form 8-K was filed on November 4, 2003, including, as an exhibit, pro forma financial statements, in connection with the sale of parts of the Partnership's crude oil pipeline and associated gathering and marketing operations.
A Current Report on Form 8-K was furnished October 15, 2003, providing, under Items 7, 9 and 12, the Partnership's news release that announced the signing of a purchase and sale agreement to sell parts of the Partnership's crude oil pipeline and associated gathering and marketing operations and the signing of a non-binding letter of intent to purchase a volumetric production payment from Denbury.
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 on the 29th day of March, 2004.
GENESIS ENERGY, L.P. (A Delaware Limited Partnership)
By: GENESIS ENERGY, INC., as General Partner
By: /s/ Mark J. Gorman ------------------------------------- Mark J. Gorman Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
GENESIS ENERGY, L.P. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
INDEPENDENT AUDITORS' REPORT
Genesis Energy, L.P. Houston, Texas
We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P., (the "Partnership") as of December 31, 2003 and 2002, and the related consolidated statements of operations, comprehensive income, partners' capital and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Notes 2 and 4 to the consolidated financial statements, effective January 1, 2002, the Partnership changed its method of accounting for goodwill and discontinued operations. As discussed in Note 17 to the consolidated financial statements, in 2001, the Partnership changed its method of accounting for derivative financial instruments.
/s/ Deloitte & Touche LLP - ------------------------- DELOITTE & TOUCHE LLP Houston, Texas
March 19, 2004
GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts)
GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS-CONTINUED (In thousands, except per unit amounts)
The accompanying notes are an integral part of these consolidated financial statements.
GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Genesis Energy, L.P. ("GELP" or the "Partnership") is a publicly traded Delaware limited partnership engaged in gathering, marketing and transportation of crude oil and wholesale marketing of carbon dioxide (CO2). We were formed in December 1996 through an initial public offering of 8.6 million Common Units, representing limited partner interests in GELP of 98%. The General Partner of GELP is Genesis Energy, Inc. (the "General Partner") which owns a 2% general partner interest in GELP. The General Partner is owned by Denbury Gathering & Marketing, Inc. a subsidiary of Denbury Resources Inc. Denbury and its subsidiaries are hereafter referred to as Denbury.
In November 2003, an additional 0.7 million Common Units were sold to our general partner in a private placement. These Common Units are not registered with the Securities and Exchange Commission. See Note 7.
Genesis Crude Oil, L.P. is the operating limited partnership and is owned 99.99% by GELP and 0.01% by the General Partner. Genesis Crude Oil, L.P. has two subsidiary partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA, L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred to as GCOLP.
Basis of Presentation
The accompanying financial statements and related notes present the consolidated financial position as of December 31, 2003 and 2002 for GELP and its results of operations, cash flows and changes in partners' capital for the years ended December 31, 2003, 2002 and 2001, and changes in comprehensive income for the years ended December 31, 2003, 2002 and 2001.
All significant intercompany transactions have been eliminated. Certain reclassifications were made to prior period amounts to conform to current period presentation. Such reclassifications had no effect on reported net income, total assets, total liabilities or partners' equity.
No provision for income taxes related to the operation of GELP is included in the accompanying consolidated financial statements; as such income will be taxable directly to the partners holding partnership interests in the Partnership.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates that we make include: (1) estimated useful lives of assets, which impacts depreciation and amortization, (2) accruals related to revenues and expenses, (3) liability and contingency accruals, (4) estimated fair value of assets and liabilities acquired, and (5) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred. While we believe these estimates reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. The Partnership has no requirement for compensating balances or restrictions on cash.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Inventories
Crude oil inventories held for sale are valued at the lower of average cost or market. Fuel inventories are carried at the lower of cost or market.
Fixed Assets
Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line method over the respective estimated useful lives of the assets. Asset lives are 5 to 15 years for pipelines and related assets, 3 to 7 years for vehicles and transportation equipment, and 3 to 10 years for buildings, office equipment, furniture and fixtures and other equipment.
Long-lived assets are reviewed for impairment. In 2001, we recorded a charge for impairment of our pipeline assets as we did not believe the recorded values of the assets could be recovered through future cash flows. On January 1, 2002, we adopted Statement of Financial Accounting Standards No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." Under SFAS No. 144, an asset shall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows.
Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset.
Certain volumes of crude oil are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil volumes are carried at their weighted average cost.
We account for asset retirement obligations in accordance with SFAS 143. SFAS 143 requires that the cost for asset retirement obligations be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense systematically as with depreciation. With respect to our pipelines, federal regulations will require us to purge the crude oil from our pipelines when the pipelines are retired. Our right of way agreements do not require us to remove pipe or otherwise perform remediation upon taking the pipelines out of service. Many of our truck unload stations are on leased sites that require that we remove our improvements upon termination of the lease term, however the lease terms are continuous until a party to the lease gives notice that it wishes the lease to terminate. However the fair value of the asset retirement obligations cannot be reasonably estimated, as the settlement dates are indeterminate. We will record such asset retirement obligations in the period in which we determine the settlement dates.
In the third quarter of 2003, we recorded a liability in the amount of $0.7 million representing the anticipated cost to remove a pipeline from offshore waters of the State of Louisiana. The costs are expected to be incurred before June 30, 2004.
CO2 and Other Assets
Other assets consist primarily of CO2 assets and intangibles. The CO2 assets include a volumetric production payment and long-term contracts to sell the CO2 volume. The contract value is being amortized on a units-of-production method. See Note 5.
Intangibles included a covenant not to compete, which was amortized over five years ending during 2003, and credit facility fees which are being amortized over the period the facility is in effect.
Minority Interests
Minority interests represent a 0.01% general partner interest in GCOLP held by the General Partner.
Environmental Liabilities
We provide for the estimated costs of environmental contingencies when liabilities are likely to occur and reasonable estimates can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenue Recognition
Revenues from gathering and marketing of crude oil are recognized when title to the crude oil is transferred to the customer. Revenues from transportation of crude oil by our pipelines are recognized upon delivery of the barrels to the location designated by the shipper. Pipeline loss allowance revenues are recognized to the extent that pipeline loss allowances charged to shippers exceed pipeline measurement losses for the period based upon the fair market value of the crude oil upon which the allowance is based.
Revenues from CO2 activities are recorded when title transfers to the customer at the inlet meter of the customer's facility.
Cost of Sales
Crude oil cost of sales consists of the cost of crude oil and field and pipeline operating expenses. Field and pipeline operating expenses consist primarily of labor costs for drivers and pipeline field personnel, truck rental costs, fuel and maintenance, utilities, insurance and property taxes.
Cost of sales for the CO2 activities consists of a transportation fee charged by Denbury (currently $0.16 per Mcf) to transport the CO2 to the customer through Denbury's pipeline.
Derivative Instruments and Hedging Activities
We minimize our exposure to price risk by limiting our inventory positions, therefore we rarely need to use derivative instruments. In 2003, we used derivative instruments only once. However should we use derivative instruments to hedge exposure to price risk, we would account for those derivative transactions in accordance with Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities", as amended and interpreted. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded on the balance sheet as assets and liabilities based on the derivative's fair value. Changes in the fair value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, the derivative's gains and losses offset related results on the hedged item in the income statement. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting.
SFAS No. 133 designates derivatives that hedge exposure to variable cash flows of forecasted transactions as cash flow hedges and the effective portion of the derivative's gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. If a derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements and is accounted for using traditional accrual accounting.
Net Income Per Common Unit
Basic and diluted net income per Common Unit is calculated on the weighted average number of outstanding Common Units, after exclusion of the 2 percent General Partner interest from net income. The weighted average number of Common Units outstanding was 8,714,845, 8,624,554 and 8,623,741 for the years ended December 31, 2003, 2002 and 2001, respectively. Diluted net income per Common Unit did not differ from basic net income per Common Unit for any period presented. See Note 7 for a computation of net income per Common Unit.
Recent Accounting Pronouncements
We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. See Fixed Assets above.
The FASB issued SFAS No. 145, "Rescission of FASB Statements 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This statement revised accounting guidance related to the extinguishment of debt and accounting for certain lease transactions. It also amended other accounting literature to clarify its meaning, applicability and to make various technical corrections. Our adoption of this standard effective January 1, 2003 had no impact on our financial statements.
On January 1, 2003, we adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. This statement requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred rather than at the
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
date of commitment to an exit plan. This adoption of this statement had no material impact on our financial statements. During the third quarter of 2003, we recorded termination benefits related to the sale of our Texas Gulf Coast operations and, in the fourth quarter of 2003, recorded the sale of those operations. See Note 11 for information regarding this sale.
We implemented FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The information required by this interpretation is included in Note 18.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," and amended the Interpretation in December 2003. The interpretation states that certain variable interest entities (VIE) may be required to be consolidated into the results of operations and financial position of the entity that is the primary beneficiary. The provisions of the interpretation were effective immediately for VIEs created after January 15, 2003. We do not have any VIEs. The adoption of this interpretation in 2003 had no effect on our financial statements.
We adopted SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as of January 1, 2003. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. As there are no outstanding grants of Partnership units under any compensation plans of the Partnership, the adoption of this statement had no effect on our financial position, results of operations, cash flows or disclosure requirements.
On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows.
In May 2003, The FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain freestanding instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or asset in some circumstances). We adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement had no effect on our financial position, results of operations or cash flows.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. INVENTORIES
Inventories consisted of the following (in thousands).
4. FIXED ASSETS
Fixed assets consisted of the following (in thousands).
Depreciation expense, including discontinued operations, was $5,970,000, $4,965,000 and $6,228,000 for the years ended December 31, 2003, 2002, and 2001, respectively. In 2001, the Partnership recorded an impairment charge related to its pipeline assets of $38,049,000. See Note 9.
5. CO2 AND OTHER ASSETS
Carbon Dioxide (CO2) Assets
We purchased the CO2 assets from Denbury for $24.4 million in cash in November 2003. These assets included the assignment of an interest in 167.5 billion cubic feet (Bcf) of CO2, under a volumetric production payment and Denbury's existing long-term CO2 supply agreements with three of its industrial customers.
The volumetric production payment entitles us to a maximum daily quantity of CO2 of 52,500 million cubic feet (Mcf) per day through December 31, 2009, 43,000 Mcf per day for the calendar years 2010 through 2012 and 25,000 Mcf per day beginning in 2013 until we have received all volumes under the production payment. Under the terms of a transportation agreement with Denbury, Denbury will process and deliver this CO2 to our industrial customers and receive a fee of $0.16 per Mcf, subject to inflationary adjustments, from us for those transportation services.
The terms of the contracts with the industrial customers include minimum take-or-pay and maximum delivery volumes. The three industrial contracts extend through 2010, 2012 and 2015.
The CO2 assets are being amortized on a units-of-production method. After purchase price adjustments, we had 164.9 Bcf of CO2 at acquisition, and the $24.4 million cost is being amortized based on the volume of CO2 sold each month. For the two months in 2003 when we owned the CO2 assets, we recorded amortization of $328,000. Based on the historical deliveries of CO2 to the customers (which have exceeded minimum take-or-pay volumes), we would expect that amortization for the next five years to be approximately $2,147,000 annually.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Assets
Other assets consisted of the following (in thousands).
In 2001, the Partnership recorded an impairment charge related to goodwill of $7,012,000, which reduced the net book value of goodwill to zero at December 31, 2001. See Note 11. In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," which we adopted January 1, 2002, we test other intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. As of December 31, 2003, no impairment has occurred of our remaining intangible assets.
Amortization expense for goodwill was $470,000 for the year ended December 31, 2001. Amortization expense for the covenant-not-to-compete was $205,000 for the year ended December 31, 2003 and $848,000 for the each of the years ended December 31, 2002 and 2001. Accumulated amortization of the covenant-not-to-compete was $4,033,000 at December 31, 2002. The covenant-not-to-compete was fully amortized and expired in 2003.
Amortization expense for the credit facility fees for the year ended December 31, 2003 was $298,000. Additionally in 2003, we charged to expense $733,000 of fees related to the facility that existed at the end of 2002. In 2002 and 2001, we recorded $456,000 and $23,000 of amortization of credit facility fees, respectively.
6. DEBT
In March 2003, the Partnership entered into $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Facility"). The Fleet Facility also has a sublimit for working capital loans in the amount of $25 million, with the remainder of the facility available for letters of credit.
The key terms of the Fleet Facility are as follows:
- Letter of credit fees are based on the usage of the Fleet Facility in relation to the borrowing base and will range from 2.00% to 3.00%. At December 31, 2003, the rate was 2.00%.
- The interest rate on working capital borrowings is also based on the usage of the Fleet Facility in relation to the borrowing base. Loans may be based on the prime rate or the LIBOR rate, at our option. The interest rate on prime rate loans can range from the prime rate plus 1.00% to the prime rate plus 2.00%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.00% to the LIBOR rate plus 3.00%. At December 31, 2003, we borrowed at the prime rate plus 1.00%.
- We pay a commitment fee on the unused portion of the $65 million commitment. This commitment fee is also based on the usage of the Fleet Facility in relation to the borrowing base and will range from 0.375% to 0.50%. At December 31, 2003, the commitment fee rate was 0.375%.
- The amount that we may have outstanding cumulatively in working capital borrowings and letters of credit is subject to a Borrowing Base calculation. The Borrowing Base is defined in the Fleet Facility generally to include cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly.
- Collateral under the Fleet Facility consists of our accounts receivable, inventory, cash accounts, margin accounts and fixed assets.
- The Fleet Facility contains covenants requiring a minimum current ratio, a minimum leverage ratio, a minimum cash flow coverage ratio, a maximum ratio of indebtedness to capitalization, a minimum
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EBITDA (earnings before interest, taxes, depreciation and amortization), and limitations on distributions to Unitholders.
Under the Fleet Facility, distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage by certain amounts. See additional discussion below under Note 7.
At December 31, 2003, we had $7.0 million outstanding under the Fleet Facility. Due to the revolving nature of loans under the Fleet Facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of March 14, 2006. At December 31, 2003, we had letters of credit outstanding under the Fleet Facility totaling $21.6 million, comprised of $10.0 million and $10.8 million for crude oil purchases related to December 2003 and January 2004, respectively and $0.8 million related to other business obligations. We were in compliance with the Fleet Facility covenants at December 31, 2003.
7. PARTNERS' CAPITAL AND DISTRIBUTIONS
Partners' Capital
During 2001, 2002 and the first ten months of 2003, partnership equity consisted of the general partner interest of 2% and 8.6 million Common Units representing limited partner interests of 98%. The Common Units were sold to the public in an initial public offering in December 1996. In November 2003, we issued 688,811 Common Units to our General Partner in exchange for $4,925,000. We received $101,000 from the general partner for its proportionate capital contribution. At December 31, 2003, a total of 9,313,811 Common Units were outstanding.
The general partner interest is held by our General Partner. The Partnership is managed by the General Partner. The General Partner also holds a 0.01% general partner interest in GCOLP, which is reflected as a minority interest in the consolidated balance sheet at December 31, 2003.
The Partnership Agreement authorizes the General Partner to cause GCOLP to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other GCOLP needs.
Distributions
Generally, we will distribute 100% of our Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. The target minimum quarterly distribution ("MQD") for each quarter is $0.20 per unit. For 2001, we paid distributions of $0.20 per unit ($1.8 million in total) per quarter for the first three quarters. For the fourth quarter of 2001 and for all of 2002, we did not pay any regular quarterly distributions. We did pay a special distribution of $0.20 per unit ($1.7 million in total) in December 2002 to help mitigate the tax effects of income allocations for that year. Beginning with the distribution for the first quarter of 2003, we paid a regular quarterly distribution of $0.05 per unit ($0.4 million in total per quarter). For the fourth quarter of 2003, we increased our quarterly distribution to $0.15 per unit ($1.4 million in total), which was paid in February 2004.
Under the Fleet Agreement, a provision requires that the Borrowing Base exceed the usage under the Fleet Agreement by at least $10 million plus the quarterly distribution, measured once each month, in order for us to make a distribution for the quarter.
Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, the general partner generally is entitled to receive 13.3% of any distributions in excess of $0.25 per unit, 23.5% of any distributions in excess of $0.28 per unit and 49% of any distributions in excess of $0.33 per unit without duplication. We have not paid any incentive distributions through December 31, 2003.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net Income Per Common Unit
The following table sets forth the computation of basic net income per Common Unit for 2003, 2002, and 2001 (in thousands, except per unit amounts).
8. BUSINESS SEGMENT INFORMATION
Our operations consist of three operating segments: (1) Crude Oil Gathering and Marketing - the purchase and sale of crude oil at various points along the distribution chain; (2) Crude Oil Pipeline Transportation - interstate and intrastate crude oil pipeline transportation; and (2) CO2 marketing - the sale of CO2 acquired under a volumetric production payment to industrial customers. Prior to 2003, we managed our crude oil gathering, marketing and pipeline operations as a single segment. The tables below reflect all periods presented as though the current segment designations had existed, and include only continuing operations data.
We evaluate segment performance based on segment margin before depreciation and amortization. All of our revenues are derived from, and all of our assets are located in the United States.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) Intersegment sales were conducted on an arm's length basis.
(b) Segment margin was calculated as revenues less cost of sales and operations expense. A reconciliation of segment margin to income from continuing operations for each year presented is as follows:
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. IMPAIRMENT OF PIPELINE ASSETS
In the fourth quarter of 2001, as a result of declining revenues and rising costs from its pipeline operations for operations and maintenance combined with regulatory changes requiring additional testing for pipeline integrity, the Partnership determined that the estimated undiscounted future cash flows did not support the carrying value of its pipelines. Under Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of" (SFAS 121) (the relevant accounting guidance at that time), the carrying value of the assets must be reduced to the fair value of the assets. The estimated fair value of the pipelines was determined by reducing the estimated undiscounted future cash flows plus salvage value to its present value at December 31, 2001. Because the goodwill on the consolidated balance sheet was generated from the acquisition of the pipeline assets, the carrying value of the net goodwill was reduced to zero with the remaining impairment allocated to the fixed assets. An impairment charge totaling $45.1 million was recorded for the pipeline assets and goodwill. $9.6 million of this impairment charge related to continuing operations, with the remaining $35.5 million included in discontinued operations.
10. OTHER OPERATING CHARGES
In each of the third quarter of 2002 and the fourth quarter of 2001, the Partnership recorded a charge of $1.5 million, for a total of $3.0 million, related to environmental matters from the Mississippi spill that occurred in 1999. These charges are reflected as other operating charges on the consolidated statement of operations for 2002 and 2001.
11. DISCONTINUED OPERATIONS
In the fourth quarter of 2003, we sold a significant portion of our Texas Pipeline System and the related crude oil gathering and marketing operations to TEPPCO Crude Oil, L.P. Additionally we sold other segments of our Texas Pipeline System that had been idled in 2002 to Blackhawk Pipeline, L.P., an affiliate of Multifuels, Inc., which plans to convert the segments to natural gas service. Some remaining segments not sold to these parties were abandoned in place.
The sale of these assets was the result of an initiative started in 2002 to evaluate our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce cost or risk of operation. We determined we should consider selling these assets due to potential risks to the continuation of our revenue stream that may result from consolidation of pipeline assets in the area and projections of maintenance capital costs that may occur. We also determined that other segments of the Texas Gulf Coast operations had little value and should be abandoned in place or sold to reduce costs or risks.
TEPPCO paid us $21.6 million for the assets it acquired. TEPPCO also assumed the responsibilities for unpaid royalties related to the crude oil purchase and sale contracts it assumed and we transferred $0.6 million to TEPPCO for those liabilities.
We entered into various agreements with TEPPCO including (a) a transitional services agreement whereby GELP will provide the use of certain assets that TEPPCO did not acquire and pipeline monitoring services at least through April 30, 2004, and (b) a joint tariff agreement whereby TEPPCO will invoice and collect and share with us
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the tariffs for transportation on the pipeline being sold and the segments we retained at least through October 31, 2004. We also agreed not to compete with TEPPCO in a 40-county area in Texas surrounding the pipeline for a five year period.
We retained responsibility for environmental matters related to the operations sold to TEPPCO for the period prior to October 31, 2003, subject to certain conditions. TEPPCO will pay the first $25,000 for any environmental claim up to an aggregate of $100,000. We would be responsible for any environmental claim in excess of these amounts up to an aggregate total of $2 million. TEPPCO has purchased an environmental insurance policy for amounts in excess of our $2 million responsibility and we reimbursed TEPPCO for one-half of the policy premium. Our responsibility to indemnify TEPPCO will cease in ten years.
During 2003, we recorded $0.4 million in termination benefits related to the sale to TEPPCO. These benefits included retention bonuses and severance pay for employees affected by the sale.
Under the terms of the sale to Blackhawk, we received no consideration from Blackhawk for the sale and agreed to provide transition services through March 31, 2004. We retained responsibility for any environmental matters related to the pipeline segments acquired by Blackhawk through December 31, 2003, however that responsibility will cease in ten years.
The assets we abandoned had been idle since 2002 or earlier. The net book value of these assets was charged to impairment expense in 2001.
Operating results from the discontinued operations for the years ended December 31, 2003, 2002 and 2001 were as follows:
12. TRANSACTIONS WITH RELATED PARTIES
Except for below-market guaranty fees paid in 2001 and 2002 to Salomon Smith Barney Holdings Inc. ("Salomon"), sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than those conducted with unaffiliated parties. Salomon was the owner of the General Partner until May 2002.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Sales and Purchases of Crude Oil
Denbury became a related party in May 2002. Purchases of crude oil from Denbury for the year ended December 31, 2003, were $59.7 million. Purchases from Denbury during the year ended December 31, 2002, while it was a related party (May to December) were $26.5 million and purchases during the period before it became an affiliate were $10.9 million. Purchases from Denbury are partially secured by letters of credit.
Genesis and Salomon ceased to be related parties in May 2002. During the period in 2002 when Salomon was a related party, sales totaling $3.0 million were made to Phibro, Inc., ("Phibro"), a subsidiary of Salomon. Purchases and sales of $36.7 million and $29.8 million, respectively, were made in 2001 with Phibro. These transactions were bulk and exchange transactions.
General and Administrative Services
We do not directly employ any persons to manage or operate our business. Those functions are provided by the General Partner. We reimburse the General Partner for all direct and indirect costs of these services. Total costs reimbursed to the General Partner by us were $16,028,000, $17,280,000, and $18,089,000 for the years ended December 31, 2003, 2002 and 2001, respectively.
Due to Related Parties
At December 31, 2003 and 2002, we owed Denbury $6.9 million and $4.1 million, respectively, for purchases of crude oil. Additionally, we owed Denbury $0.1 million for CO2 transportation services at December 31, 2003. We owed the General Partner $0.1 million and $0.6 million at December 31, 2003 and 2002, respectively, for administrative services.
Directors' Fees
In 2003, we paid $120,000 to Denbury for the services of four of Denbury's officers who serve as directors of the General Partner, the same rate at which our independent directors were paid.
CO2 Volumetric Production Payment and Transportation
We acquired a volumetric production payment from Denbury in November 2003 for $24.4 million. Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver the CO2 for us to our customers. For November and December 2003, we paid Denbury $355,000 for these transportation services related to our sales of CO2. See Note 5.
Financing
Our general partner guarantees our obligations under the Fleet Facility. Our general partner that guarantees the obligations is a wholly-owned subsidiary of Denbury. The obligations are not guaranteed by Denbury or any of its other subsidiaries.
Citicorp Credit Agreement
In December 2001, Citicorp began providing us with a working capital and letter of credit facility. Citicorp and Salomon are both subsidiaries of Citicorp, Inc. From January 1, 2002, until May 14, 2002, when Citicorp ceased to be a related party, we incurred letter of credit fees, interest and commitment fees totaling $396,000 under the Credit Agreement. In December 2001, we paid Citicorp $900,000 as a fee for providing the facility. This facility fee was being amortized to earnings over the two-year life of the Credit Agreement and was included in interest expense on the consolidated statements of operations. When the facility was replaced in March 2003, the unamortized balance of this fee totaling $371,000 was charged to interest expense. In 2001, the Partnership paid Citicorp for interest and commitment fees totaling $27,000.
Guaranty Fees
In 2001, Salomon provided a guaranty facility to the Partnership and, from January 2002 to April 2002, Salomon provided guaranties under a transition arrangement with Salomon, Citicorp and the Partnership. For the years ended December 31, 2002 and 2001, the Partnership paid Salomon $61,000 and $1,250,000, respectively, for guarantee fees. The guarantee fees are included as a component in cost of crude on the consolidated statements of operations. These guarantee fees were less than the cost of a letter of credit facility from a bank.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. SUPPLEMENTAL CASH FLOW INFORMATION
Cash received by us for interest during the years ended December 31, 2003, 2002 and 2001 was $34,000, $68,000, and $195,000, respectively. Cash payments for interest were $1,194,000, $537,000, and $1,391,000 during the years ended December 31, 2003, 2002 and 2001, respectively.
14. EMPLOYEE BENEFIT PLANS
We do not directly employ any of the persons responsible for managing or operating our activities. Employees of the General Partner provide those services and are covered by various retirement and other benefit plans.
In order to encourage long-term savings and to provide additional funds for retirement to its employees, the General Partner sponsors a profit-sharing and retirement savings plan. Under this plan, the General Partner's matching contribution is calculated as an equal match of the first 3% of each employee's annual pretax contribution and 50% of the next 3% of each employee's annual pretax contribution. The General Partner also made a profit-sharing contribution of 3% of each eligible employee's total compensation. The expenses included in the consolidated statements of operations for costs relating to this plan were $507,000, $564,000, and $603,000 for the years ended December 31, 2003, 2002 and 2001, respectively.
The General Partner also provided certain health care and survivor benefits for its active employees. In 2003, 2002 and 2001, these benefit programs were self-insured, with a catastrophic insurance policy to limit our costs. The General Partner plans to continue self-insuring these plans in the future. The expenses included in the consolidated statements of operations for these benefits were $1,368,000, $1,360,000, and $1,526,000 in 2003, 2002 and 2001, respectively.
Stock Appreciation Rights Plan
In December 2003, the Board approved a Stock Appreciation Rights (SAR) plan for all employees. Under the terms of this plan, all regular, full-time active employees and the members of the Board are eligible to participate in the plan. The plan is administered by the Compensation Committee of the Board, who shall determine, in its full discretion, the number of rights to award, the grant date of the units and the formula for allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one Common Unit.
The rights have a term of 10 years from the date of grant. The initial award to a participant will vest one-fourth each year beginning with the first anniversary of the grant date of the award. Subsequent awards to participants will vest on the fourth anniversary of the grant date. If the right has not been exercised at the end of the ten year term and the participant has not terminated his employment with us, the right will be deemed exercised as of the date of the right's expiration and a cash payment will be made as described below.
Upon vesting, the participant may exercise his rights and receive a cash payment calculated as the difference between the average of the closing market price of our Common Units for the ten days preceding the date of exercise over the strike price of the right being exercised. The cash payment to the participant will be net of any applicable withholding taxes required by law. If the Committee determines, in its full discretion, that it would cause significant financial harm to the Partnership to make cash payments to participants who have exercised rights under the plan, then the Committee may authorize deferral of the cash payments until a later date.
Termination for any reason other than death, disability or normal retirement (as these terms are defined in the plan) will result in the forfeiture of any non-vested rights Upon death, disability or normal retirement, all rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change in control (as defined in the plan) all rights will become fully vested.
On December 31, 2003 awards of 423,057 rights were allocated to participants with a strike price of $9.26 per right. In 2003, we recorded non-cash expense of $228,000 for the increase between the strike price of the outstanding rights and the closing market price for Common Units on December 31, 2003. In 2001, we recorded expense of $55,000 related to a restricted unit plan that has been terminated.
Bonus Plan
In March 2003, the Compensation Committee of the Board of Directors of the General Partner approved a Bonus Plan (the "Bonus Plan") for all employees of the General Partner. The Bonus Plan is designed to enhance the
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
financial performance of the Partnership by rewarding all employees for achieving financial performance objectives. The Bonus Plan will be administered by the Compensation Committee. Under this plan, amounts will be allocated for the payment of bonuses to employees each time GCOLP earns $1.6 million of Available Cash. The amount allocated to the bonus pool increases for each $1.6 million earned, such that a bonus pool of $2.0 million will exist if the Partnership earns $14.6 million of Available Cash.
Bonuses will be paid to employees after the end of the year, but only if distributions are made to the Common Unitholders. The amount in the bonus pool will be allocated to employees based on the group to which they are assigned. Employees in the first group can receive bonuses that range from zero to ten percent of base compensation. The next group includes employees in the professional group, who could earn a total bonus ranging from zero to twenty percent. Certain members of the professional group that are part of management or are exceptional performers are eligible to earn a total bonus ranging from zero to thirty percent. Lastly, our officers and other senior management are eligible for a total bonus ranging from zero to forty percent. The Bonus Plan will be at the discretion of the Compensation Committee, and our General Partner can amend or change the Bonus Plan at any time.
15. MAJOR CUSTOMERS AND CREDIT RISK
We derive our revenues from customers primarily in the crude oil industry. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of major international corporate entities with stable payment experience. The credit risk related to contracts which are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements.
We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met.
Marathon Ashland Petroleum LLC, ExxonMobil Corporation and Shell Oil Company accounted for 22.5%, 15.4% and 11.0% of total revenues in 2003, respectively. Marathon Ashland Petroleum LLC and ExxonMobil Corporation accounted for 18.5% and 13.6% of total revenues in 2002, respectively. In 2001, BP Amoco Corporation subsidiaries and Enron Corporation subsidiaries accounted for 10.6% and 14.1% of total revenues, respectively. The majority of the revenues from these five customers in all three years relate to our gathering and marketing operations.
16. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities in the Consolidated Balance Sheets approximated fair value due to the short maturity of these instruments. Additionally, the carrying value of the long-term debt approximated fair value due to its floating rate of interest.
17. DERIVATIVES
Our market risk in the purchase and sale of its crude oil contracts is the potential loss that can be caused by a change in the market value of the asset or commitment. In order to hedge our exposure to such market fluctuations, we may enter into various financial contracts, including futures, options and swaps. Historically, any contracts we have used to hedge market risk were less than one year in duration. During 2003 we did not use any hedging instruments.
We may utilize crude oil futures contracts and other financial derivatives to reduce our exposure to unfavorable changes in crude oil prices. On January 1, 2001, we adopted the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", which established new accounting and reporting guidelines for derivative instruments and hedging activities. Every derivative instrument (including certain derivative instruments embedded in other contracts) must be recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
related results on the hedged item in the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
We mark to fair value our derivative instruments at each period end with changes in fair value of derivatives not designated as hedges being recorded as unrealized gains or losses. Such unrealized gains or losses will change, based on prevailing market prices, at each balance sheet date prior to the period in which the transaction actually occurs. Unrealized gains or losses on derivative transaction qualifying as hedges are reflected in other comprehensive income.
In general, SFAS No. 133 requires that at the date of initial adoption, the difference between the fair value of derivative instruments and the previous carrying amount of those derivatives be recorded in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. On January 1, 2001, recognition of our derivatives resulted in a gain of $0.5 million, which was recognized in the consolidated statement of operations as the cumulative effect of adopting SFAS No. 133. Certain derivative contracts related to written option contracts had been recorded on the balance sheet at fair value at December 31, 2000, so no adjustment was necessary for those contracts upon adoption of SFAS No. 133.
We regularly review our contracts to determine if the contracts qualify for treatment as derivatives. We had no contracts qualifying for treatment as derivatives at December 31, 2003.
At December 31, 2002, we determined that the only contract qualifying as a derivative was a qualifying cash flow hedge. The decrease of $39,000 in the fair value of this hedge is recorded in other comprehensive income and as accumulated other comprehensive income in the consolidated balance sheet. No hedge ineffectiveness was recognized during 2002. The anticipated transaction (crude oil sales) occurred in January 2003, and all related amounts held in other comprehensive income at December 31, 2002, were reclassified to the consolidated statement of operations in the first quarter of 2003.
We determined that all other derivative contracts qualified for the normal purchase and sale exemption at December 31, 2003 and 2002. The decrease in fair value of our net asset for derivatives not qualifying as hedges during 2002 was $2.1 million. The increase in fair value of our net asset for derivatives not qualifying as hedges during 2001 was $1.7 million. These changes in fair value are recorded in the consolidated statements of operations under the caption "Change in fair value of derivatives."
18 COMMITMENTS AND CONTINGENCIES
Commitments and Guarantees
We lease office space for our headquarters office under a long-term lease. The lease extends until October 31, 2005. We lease office space for a field office under a lease that expires in 2007. Ryder provides tractors and trailers to us under an operating lease that also includes full-service maintenance. Under the terms of the lease, we lease 46 tractors and 46 trailers. We pay a fixed monthly rental charge for each tractor and trailer and a fee based on mileage for the maintenance services. We have ordered an additional 5 tractors and trailers from Ryder that we expect to receive during the first quarter of 2004. We lease three tanks for use in our pipeline operations. The tank lease expires in 2004, however we have advised the lessor that we may want to extend the lease. Additionally, we lease a segment of pipeline. Under the terms of that lease, we make lease payments based on throughput, and we have no minimum volumetric or financial requirements remaining. We also lease service vehicles for our field personnel.
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The future minimum rental payments under all non-cancelable operating leases as of December 31, 2003, were as follows (in thousands).
Total operating lease expense was as follows (in thousands).
We have guaranteed $3.3 million of residual value related to the leases of tractors and trailers. We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote.
GELP has guaranteed crude oil purchases of GCOLP. These guarantees, totaling $11.4 million, were provided to counterparties. To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in the consolidated balance sheet.
GELP, the General Partner and the subsidiaries of GCOLP have guaranteed the payments by GCOLP to Fleet under the terms of the Fleet Facility related to borrowings and letters of credit. Borrowings at December 31, 2003 were $7.0 million and are reflected in the consolidated balance sheet. To the extent liabilities exist under the letters of credit, such liabilities are included in the consolidated balance sheet.
We have contractual commitments (forward contracts) arising in the ordinary course of our crude oil marketing activities. At December 31, 2003, the Partnership had commitments to purchase 1,854,000 barrels of crude oil in January 2004, and 986,000 barrels of crude oil between February 2004, and October 2004. We had commitments to sell 1,865,000 barrels of crude oil in January 2004, and 690,000 barrels of crude oil between February 2004 and June 2004. All of these contracts are associated with market-price-related contracts. The total commitment to purchase crude oil would be valued at $89.4 million, using market prices at December 31, 2003. The total commitment to sell crude oil would be valued at $82.0 million, using market prices at December 31, 2003.
In general, we expect to increase our expenditures in the future to comply with higher industry and regulatory safety standards and Securities and Exchange Commission (SEC) regulations. During 2004, we expect to spend between $0.5 million and $1.0 million related to compliance with the requirements of the Sarbanes Oxley Act of 2002 as required by the SEC. While the total amount of increased expenditures cannot be accurately estimated at this time, we anticipate that we will expend a total of approximately $2.2 million in 2004 and 2005 for testing and rehabilitation under regulations requiring assessment of the integrity of crude oil pipelines.
Pennzoil Litigation
We were named one of the defendants in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, Cause No. 2001-01176. Pennzoil-Quaker State Company ("PQS") was seeking property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. In December 2003, our insurance carriers settled this litigation for $12.8 million. We have recorded in Accrued Liabilities on our consolidated statement of operations the obligation for this settlement, and in Insurance Receivable we have recorded the insurance reimbursement for this obligation. The settlement was funded in
GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
February 2004, with certain insurance companies directly funding $5.9 million of the payment and $6.9 million was funded by us. We will receive reimbursement of the $6.9 million from the insurance company no later than May 2004.
PQS is also a defendant in five suits brought by neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial District Court, Caddo Parish, Louisiana, Cause Nos. 455,647-A. 455,658-B, 455,655-A, 456,574-A, and 458,379-C. PQS has brought third party demand against Genesis and others for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against Genesis is without merit and intend to vigorously defend ourselves in this matter.
Environmental
On December 20, 1999, we had a spill of crude oil from our Mississippi System. Approximately 8,000 barrels of oil spilled from the pipeline near Summerland, Mississippi, and entered a creek nearby. A portion of the oil then flowed into the Leaf River. The oil spill is covered by insurance and the direct financial impact to us of the cost of the clean-up has not been material. Included in insurance receivable on the consolidated balance sheet at December 31, 2003 is $2.8 million related to this spill. Management of the Partnership has reached an agreement in principle with the US Environmental Protection Agency and the Mississippi Department of Environmental Quality for the payment of fines under environmental laws with respect to this oil spill. Based on this agreement in principle, in 2001 and 2002, a total accrual of $3.0 million was recorded for these fines. The fines will not be covered by insurance.
We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities, however no assurance can be made that such environmental releases may substantially affect our business.
Other Matters
We have taken additional security measures since the terrorist attacks of September 11, 2001 in accordance with guidance provided by the Department of Transportation and other government agencies. We cannot assure you that these security measures would prevent our facilities from a concentrated attack. Any future attacks on us or our customers or competitors could have a material effect on our business, whether insured or not. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable.
We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. Such matters presently pending are not expected to have a material adverse effect on our financial position, results of operations or cash flows.
EXHIBIT INDEX
Exhibits
---------- * Filed herewith
+ A management contract or compensation plan or arrangement.