10-K 1 f10k02.txt 10K GENESIS ENERGY, L.P UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ------- ACT OF 1934 For the fiscal year ended December 31, 2002 OR -------TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-12295 GENESIS ENERGY, L.P. (Exact name of registrant as specified in its charter) Delaware 76-0513049 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 500 Dallas, Suite 2500, Houston, Texas 77002 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (713) 860-2500 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Title of Each Class on Which Registered ------------------- --------------------- Common Units American Stock Exchange Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X| Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934). ------- Aggregate market value of the Common Units held by non-affiliates of the Registrant, based on closing prices in the daily composite list for transactions on the American Stock Exchange on June 28, 2002, was approximately $32,861,250. At March 3, 2003, 8,625,000 Common Units were outstanding. 2 GENESIS ENERGY, L.P. 2002 FORM 10-K ANNUAL REPORT Table of Contents Page Part I Item 1. Business....................................................... 3 Item 2. Properties..................................................... 10 Item 3. Legal Proceedings.............................................. 11 Item 4. Submission of Matters to a Vote of Security Holders............ 11 Part II Item 5. Market for Registrant's Common Units and Related Security Holder Matters................................................. 11 Item 6. Selected Financial Data........................................ 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................................... 13 Item 7a. Quantitative and Qualitative Disclosures about Market Risk..... 32 Item 8. Financial Statements and Supplementary Data.................... 32 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................................... 32 Part III Item 10. Directors and Executive Officers of the Registrant............. 33 Item 11. Executive Compensation......................................... 34 Item 12. Security Ownership of Certain Beneficial Owners and Management. 36 Item 13. Certain Relationships and Related Transactions................. 37 Item 14. Controls and Procedures........................................ 37 Part IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K 38 CERTIFICATIONS ........................................................... 41 3 PART I Item 1. Business General Genesis Energy, L.P., a Delaware limited partnership, was formed in December 1996. We conduct our operations through our affiliated limited partnership, Genesis Crude Oil, L.P. and its subsidiary partnerships (collectively, the "Partnership" or "Genesis"). We are an independent gatherer and marketer of crude oil. Our operations are concentrated in Texas, Louisiana, Alabama, Florida, Mississippi and New Mexico. In our gathering and marketing business, we are principally engaged in the purchase and aggregation of crude oil at the wellhead for resale at various points along the crude oil distribution chain, which extends from the wellhead to aggregation at terminal facilities, refineries and other end markets (the "Distribution Chain"). Our gathering and marketing margins are generated by buying crude oil at competitive prices, efficiently transporting or exchanging the crude oil along the Distribution Chain and marketing the crude oil to customers at favorable prices. We utilize our trucking fleet of 74 leased tractor-trailers and our gathering lines to transport crude oil. We also transport purchased crude oil on trucks, barges and pipelines owned and operated by third parties. In the fourth quarter of 2002, we purchased an average of approximately 63,000 barrels per day of crude oil at the wellhead. We also make bulk purchases of crude oil at pipeline and terminal facilities. When opportunities arise to increase margin or to acquire a grade of crude oil that more nearly matches the specifications for crude oil we are obligated to deliver, we may exchange crude oil with third parties through exchange or buy/sell agreements. These purchases were significantly reduced in 2002 compared to prior years. In the fourth quarter of 2002, our bulk and exchange transactions averaged 20,000 barrels per day, down from 260,000 barrels per day in the fourth quarter of 2001. The reduction is attributable primarily to credit requirements for these transactions as discussed below. In addition to our gathering and marketing business, our operations include transportation of crude oil at regulated published tariffs on our three common carrier pipeline systems. We transported a total of approximately 77,000 barrels per day on our three common carrier crude oil pipeline systems and related gathering lines during the fourth quarter of 2002. These systems are the Texas System, the Jay System extending between Florida and Alabama, and the Mississippi System extending between Mississippi and Louisiana. These pipeline systems have numerous points where the crude oil owned by the shipper can be injected into the pipeline for delivery to or transfer to connecting pipelines. Genesis earns a tariff for the transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to delivery point. Genesis Energy, Inc. (the "General Partner"), a Delaware corporation, serves as the sole general partner of Genesis Energy, L.P., Genesis Crude Oil,L.P. (GCOLP) and GCOLP's subsidiary partnerships, Genesis Pipeline Texas, L.P.and Genesis Pipeline USA, L.P. The General Partner is owned by Denbury Gathering & Marketing, Inc., a subsidiary of Denbury Resources Inc. Denbury acquired the General Partner from Salomon Smith Barney Holdings Inc. and Salomon Brothers Holding Company Inc. in May 2002. Business Overview In our gathering and marketing business, we seek to purchase and sell crude oil at points along the Distribution Chain where gross margins can be achieved. We generally purchase crude oil at prevailing prices from producers at the wellhead under short-term contracts and then transport the crude oil along the Distribution Chain for sale to or exchange with customers. Our margins from our gathering and marketing operations are generated by 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 and the cost of supplying credit in the form of letters of credit or guaranties. We generally enter into an exchange transaction only when the cost of the exchange is less than the alternative costs that it would otherwise incur in transporting or storing the crude oil. In addition, we may exchange one grade of crude oil for another to maximize margins or meet contract delivery requirements. Gross margin from gathering, marketing and pipeline operations varies from period to period, depending to a significant extent upon changes in the supply and demand of crude oil and the resulting changes in U.S. crude oil inventory levels. 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 4 hand, and sales or future delivery obligations, on the other hand. It is our policy not to acquire and hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes. Oil prices rose in the latter half of 2002 such that the NYMEX price for WTI was $31.20 at December 31, 2002. International factors such as the strike by oil workers in Venezuela and the potential for war with Iraq as well as domestic influences such as the supply of crude oil in the United States have contributed to the price increase. 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. To the extent we have crude oil inventories, we can be impacted by market-price changes. 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. Typically 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 an individual transaction 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 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. Some purchase contracts and 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 who ultimately receive the oil. When we set a fixed bonus, we take into consideration the typical grade differences in the market.. If we then sell the oil under a contract with a floating grade differential in the formula, and that grade differential fluctuates, we can then experience an increase or decrease in our gross margin from that oil purchase and sale. This volatility in grade differentials adds volatility to our gross margins. The 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 and 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 and grade differentials, it is not practical to renegotiate every purchase contract for every change in P-Plus or a grade differential. So margins from the sale of the crude oil can be volatile as a result of these timing differences. Through the pipeline systems we own and operate, our pipeline subsidiaries transport crude oil for our gathering and marketing subsidiary and other shippers pursuant to tariff rates regulated by the Federal Energy Regulatory Commission ("FERC") or the Texas Railroad Commission. Accordingly, we offer transportation services to any shipper of crude oil, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. Pipeline revenues are a function of the level of throughput and the distance from the point where the crude oil was injected into the pipeline and the delivery point. We also can earn revenue from pipeline loss allowance volumes. In exchange for bearing the risk of pipeline volumetric losses from whatever source, we deduct volumetric pipeline loss allowances and crude quality deductions. Such allowances and deductions are offset by measurement gains and losses. When the allowances exceed measurement losses, the net pipeline loss allowance volumes are earned and recognized as income and inventory available to sell valued at the market price for the crude oil. Until the volumes are sold, they are held as inventory at the lower of cost or market value. When the volumes are sold, any difference between the carrying amount and the sale price is recognized as additional revenue. The margins from the Partnership's pipeline operations are generated by the difference between the regulated published tariff, pipeline loss allowance revenues and the fixed and variable costs of operating and maintaining the pipeline. 5 Producer Services Crude oil purchasers who buy from producers compete on the basis of competitive prices and quality of services. Through our team of crude oil purchasing representatives, we maintain relationships with more than 600 producers. We believe that our ability to offer high-quality field and administrative services to producers is a key factor in our ability to maintain volumes of purchased crude oil and to obtain new volumes. High-quality field services include efficient gathering capabilities, availability of trucks, willingness to construct gathering pipelines where economically justified, timely pickup of crude oil from tank batteries at the lease or production point, accurate measurement of crude oil volumes received, avoidance of spills and effective management of pipeline deliveries. Accounting and other administrative services include securing division orders (statements from interest owners affirming the division of ownership in crude oil purchased by the Partnership), providing statements of the crude oil purchased each month, disbursing production proceeds to interest owners and calculation and payment of production taxes on behalf of interest owners. In order to compete effectively, we must maintain records of title and division order interests in an accurate and timely manner to make prompt and correct payment of crude oil production proceeds on a monthly basis, together with the correct payment of all severance and production taxes associated with such proceeds. In 2002, we distributed payments to approximately 15,000 interest owners. Credit Our credit standing is a major consideration for parties with whom we do business. At times, in connection with our crude oil purchases or exchanges, we are required to furnish guarantees or letters of credit. In most purchases from producers and most exchanges, an open line of credit is extended by the seller up to a dollar limit, with credit support required for amounts in excess of the limit. When we market crude oil, we must determine the amount, if any, of the line of credit to be extended to any given customer. Since typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in our business. We believe that our sales are made to creditworthy entities or entities with adequate credit support. We have not experienced any nonpayment or nonperformance by our customers during 2001 or 2002. Over the last year there have been an unusual number of business failures and very large restatements by small as well as large companies in the energy industry. Because the energy industry is very credit intensive, these failures and restatements have focused attention on the credit risks of companies in the energy industry by credit rating agencies, producers and counterparties. This focus on credit has affected requests for credit from producers. While we have seen some increase in requests for credit support from producers, we have been relatively successful in obtaining open credit from most producers. When credit support has been required, we have generally been successful in adjusting the price we pay to purchase the crude oil to reflect the cost to us of providing letters of credit. Credit review and analysis are also integral to our leasehold purchases. Payment for all or substantially all of the monthly leasehold production is sometimes made to the operator of the lease, who is responsible for the correct payment and distribution of such production proceeds to the proper parties. In these situations, we must determine whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend us in the event any third party should bring a protest, action or complaint in connection with the distribution of production proceeds by the operator. Competition In the various business activities described above, we are in competition with a number of major oil companies and smaller entities. There is intense competition for leasehold purchases of crude oil. The number and location of our pipeline systems and trucking facilities give us access to domestic crude oil production throughout our area of operations. We purchase leasehold barrels from more than 600 producers. In the fourth quarter of 2002, approximately 38 percent of the leasehold barrels were purchased from ten producers, with Denbury representing eight percent of total leasehold-barrel purchases. We have considerable flexibility in marketing the volumes of crude oil that we purchase, without dependence on any single customer or transportation or storage facility. Our largest competitors in the purchase of leasehold crude oil production are Plains All American Pipeline, L.P., EOTT Energy Partners, L.P., Shell Trading Company, GulfMark Energy, Inc. and TEPPCO Partners, L.P. Additionally, we compete with many regional or 6 local gatherers who may have significant market share in the areas in which they operate. Competitive factors include price, personal relationships, range and quality of services, knowledge of products and markets, availability of trade credit and capabilities of risk management systems. Our most significant competitors in our pipeline operations are primarily common carrier and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where the Mississippi and Texas Systems deliver crude oil. The Jay System operates in an area not currently served by pipeline competitors. Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service and proximity to refineries and connecting pipelines. We believe that high capital costs, tariff regulation and problems in acquiring rights-of-way make it unlikely that other competing crude oil pipeline systems comparable in size and scope to our pipelines will be built in the same geographic areas in the near future, provided that our pipelines continue to have available capacity to satisfy demands of shippers and that our tariffs remain at competitive levels. Employees To carry out various purchasing, gathering, transporting and marketing activities, the General Partner employed, at February 14, 2003, approximately 230 employees, including management, truck drivers and other operating personnel, division order analysts, accountants, tax specialists, contract administrators, schedulers, marketing and credit specialists and employees involved in our pipeline operations. None of the employees are represented by labor unions, and we believe that relationships with our employees are good. Regulation Sarbanes-Oxley Act of 2002 In July 2002, the Sarbanes-Oxley Act of 2002 was signed into law to protect investors by improving the accuracy and reliability of corporate disclosures made pursuant to securities laws. The Securities and Exchange Commission is required to issue rules to adopt and implement the provision of Sarbanes-Oxley. The SEC has issued some final rules. Rules that are effective now that affect us are requirements for certifications by our Chief Executive Officer and Chief Financial Officer in our quarterly and annual filings with the SEC; disclosures regarding controls and procedures, disclosures regarding critical accounting estimates and policies and requirements to make filings with the SEC available on our website. Additional rules that will become effective during 2003 include disclosures regarding audit committee financial experts and charters, disclosure of our Code of Ethics for the CEO and senior financial officers, disclosures regarding contractual obligations and off-balance sheet arrangements and transactions, and requirements for filing earnings press releases with the SEC. Additionally, we will be required to include in our Form 10-K for 2003 a certification on internal accounting controls and a report from our auditors regarding that certification. Pipeline Tariff Regulation The interstate common carrier pipeline operations of the Jay and Mississippi systems are subject to rate regulation by FERC under the Interstate Commerce Act ("ICA"). FERC regulations require that oil pipeline rates be posted publicly and that the rates be "just and reasonable" and not unduly discriminatory. Effective January 1, 1995, FERC promulgated rules simplifying and streamlining the ratemaking process. Previously established rates were "grandfathered", limiting the challenges that could be made to existing tariff rates. Rates of interstate oil pipelines are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change in year to year in an index. Under the regulations, we are able to change our rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods. Rate increases made pursuant to the index will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. Alternatively, FERC allows for rate changes under three other methods--a cost-of-service methodology, competitive market showings ("Market-Based Rates"), or agreements between shippers and the oil pipeline company that the rate is acceptable ("Settlement Rates"). The pipeline tariff rates on our Mississippi and Jay Systems are either rates that were grandfathered and have been changed under the index methodology or Settlement Rates. None of our tariffs have been subjected to a protest or complaint by any shipper or other interested party. 7 Our intrastate common carrier pipeline operations in Texas are subject to regulation by the Texas Railroad Commission. The applicable Texas statutes require that pipeline rates be non-discriminatory and provide a fair return on the aggregate value of the property of a common carrier, after providing reasonable allowance for depreciation and other factors and for reasonable operating expenses. There is no case law interpreting these standards as used in the applicable Texas statutes. This is because historically, as well as currently, the Texas Railroad Commission has not been aggressive in regulating common carrier pipelines such as ours and has not investigated the rates or practices of such carriers in the absence of shipper complaints, which have been few and almost invariably have been settled informally. In 2002 we increased the tariffs on our Texas System due to higher costs to operate and maintain the pipeline. Although no assurance can be given that the tariffs we charge would ultimately be upheld if challenged, we believe that the tariffs now in effect can be sustained. Environmental Regulations We are subject to federal and state laws and regulations relating to the protection of the environment. At the federal level such laws include the Clean Air Act; the Clean Water Act; the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liability Act; and the National Environmental Policy Act. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties or in the imposition of injunctive relief. Although compliance with such laws has not had a significant effect on our business, such compliance in the future could prove to be costly, and there can be no assurance that we will not incur such costs in material amounts. The Clean Air Act regulates, among other things, the emission of volatile organic compounds in order to minimize the creation of ozone. Such emissions may occur from the handling or storage of crude oil. The required levels of emission control are established in state air quality control implementation plans. Both federal and state laws impose substantial penalties for violation of these applicable requirements. We believe that we are in substantial compliance with applicable clean air requirements. The Clean Water Act controls the discharge of oil and derivatives into certain surface waters. The Clean Water Act provides penalties for any discharges of crude oil in harmful quantities and imposes liability for the costs of removing an oil spill. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of crude oil in surface waters or into the ground. Federal and state permits for water discharges may be required. The Oil Pollution Act of 1990 ("OPA"), as amended by the Coast Guard Authorization Act of 1996, requires operators of offshore facilities and certain onshore facilities near or crossing waterways to provide financial assurance in the amount of $35 million to cover potential environmental cleanup and restoration costs. This amount is subject to upward regulatory adjustment. We believe that we are in substantial compliance with the Clean Water Act and OPA. We have developed an Integrated Contingency Plan (ICP) to satisfy components of the OPA, as amended in the Clean Water Act. The ICP also satisfies regulations of the federal Department of Transportation, the federal Occupational Safety and Health Act ("OSHA") and state regulations. This plan meets regulatory requirements as to notification, procedures, response actions, response teams, response resources and spill impact considerations in the event of an oil spill. The Resource Conservation and Recovery Act regulates, among other things, the generation, transportation, treatment, storage and disposal of hazardous wastes. Transportation of petroleum, petroleum derivatives or other commodities may invoke the requirements of the federal statute, or state counterparts, which impose substantial penalties for violation of applicable standards. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. Such persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the ordinary course of our operations, substances may be generated or handled which fall within the definition of 8 "hazardous substances." Although we have applied operating and disposal practices that werestandard in the industry at the time, hydrocarbons or other waste may have been disposed of or released on or under the property owned or leased by us or under locations where such wastes have been taken for disposal. Further, we may own or operate properties that in the past were operated by third parties whose operations were not under our control. Those properties and any wastes that may have been disposed of or released on them may be subject to CERCLA, RCRA and analogous state laws, and we potentially could be required to remediate such properties. Under the National Environmental Policy Act ("NEPA"), a federal agency, in conjunction with a permit holder, may be required to prepare an environmental assessment or a detailed environmental impact study before issuing a permit for a pipeline extension or addition that would significantly affect the quality of the environment. Should an environmental impact study or assessment be required for any proposed pipeline extensions or additions, the effect of NEPA may be to delay or prevent construction or to alter the proposed location, design or method of construction. We are subject to similar state and local environmental laws and regulations that may also address additional environmental considerations of particular concern to a state. 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 and river nearby. The spill was cleaned up, with ongoing monitoring and reduced clean-up activity expected to continue for an undetermined period of time. The oil spill is covered by insurance and the financial impact to us for the cost of the clean-up has not been material. During 2002, we reached agreement in principal with the US Environmental Protection Agency (EPA) and the Mississippi Department of Environmental Quality (MDEQ) for the payment of fines under federal and state environmental laws with respect to this 1999 spill. Based on the discussions leading to this agreement in principal, we have recorded accrued liabilities totaling of $3.0 million during 2001 and 2002. While we are pleased with the progress we have made toward resolving the uncertainty of this environmental liability during 2002, no assurance can be made that we will reach final agreement with the federal and Mississippi governments or the specific terms of a final agreement if one is reached. Safety Regulations Our crude oil pipelines are subject to construction, installation, operating and safety regulation by the Department of Transportation ("DOT") and various other federal, state and local agencies. The Pipeline Safety Act of 1992, among other things, amends the Hazardous Liquid Pipeline Safety Act of 1979 ("HLPSA") in several important respects. It requires the Research and Special Programs Administration ("RSPA") of DOT to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. In addition, the Pipeline Safety Act mandates the establishment by DOT of pipeline operator qualification rules requiring minimum training requirements for operators, and requires that pipeline operators provide maps and records to RSPA. It also authorizes RSPA to require that pipelines be modified to accommodate internal inspection devices, to mandate the installation of emergency flow restricting devices for pipelines in populated or sensitive areas, and to order other changes to the operation and maintenance of petroleum pipelines. Significant expenses could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities. On March 31, 2001, the Department of Transportation promulgated Integrity Management Plan (IMP) regulations. The IMP regulations require that we perform baseline assessments of all pipelines that could affect a High Consequence Area. The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology. A High Consequence Area (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. The IMP regulation required us to prepare an Integrity Management Plan that details the risk assessment factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to assess pipeline integrity, and an explanation of the assessment methods selected. The risk factors to be 9 considered include proximity to population areas, waterways and sensitive areas, known pipe and coating conditions, leak history, pipe material and manufacturer, cathodic protection adequacy, operating pressure levels and external damage potential. 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. As testing is complete, we are required to take prompt remedial action to address all integrity issues raised by the assessment. No assurance can be given that the cost of testing and the required rehabilitation identified will not be material costs to Genesis that may not be fully recoverable by tariff increases. In addition to the IMP, we have developed a Risk Management Plan as part of the IMP. This plan is intended to minimize the offsite consequences of catastrophic spills. As part of this program, we have developed a mapping program. This mapping program will identify HCAs and unusually sensitive areas (USAs) along the pipeline right-of-ways in addition to mapping of shorelines to characterize the potential on waterways of a spill of crude oil. States are largely preempted from regulating pipeline safety by federal law but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate. Our crude oil pipelines are also subject to the requirements of the Office of Pipeline Safety of the federal Department of Transportation regulations requiring qualification of all pipeline personnel. The Operator Qualification (OQ) program required operators to develop and submit a written program by April, 2001. The regulations also require all pipeline operators to develop a training program for pipeline personnel and qualify them on individual covered tasks at the operator's pipeline facilities by October 2002. The intent of the OQ regulations is to ensure a qualified workforce by pipeline operators and contractors when performing covered tasks on the pipeline and its facilities, thereby reducing the probability and consequences of incidents caused by human error. Our crude oil operations are also subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. We believe that our crude oil pipelines and trucking operations have been operated in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Various other federal and state regulations require that we train all employees in pipeline and trucking operations in HAZCOM and disclose information about the hazardous materials used in our operations. Certain information must be reported to employees, government agencies and local citizens upon request. In general, we expect to increase our expenditures in the future to comply with higher industry and regulatory safety standards such as those described above. While the total amount of increased expenditures cannot be accurately estimated at this time, we anticipate that we will expend a total of approximately $9.6 million in 2003 and 2004 for testing and rehabilitation under the IMP. We operate our fleet of leased trucks as a private carrier. Although a private carrier that transports property in interstate commerce is not required to obtain operating authority from the ICC, the carrier is subject to certain motor carrier safety regulations issued by the DOT. The trucking regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug testing, safety of operation and equipment, and many other aspects of truck operations. We are also subject to OSHA with respect to its trucking operations. We are subject to federal EPA regulations for the development of a written Spill Prevention Control and Countermeasure (SPCC) Plan. All trucking facilities have a current SPCC Plan and employees have received training on the SPCC Plan and regulations. Annually, trucking employees receive training regarding the transportation of hazardous materials. Commodities regulation Our price risk management operations are subject to constraints imposed under the Commodity Exchange Act and the rules of the NYMEX. The futures and options contracts that are traded on the NYMEX are subject to strict regulation by the Commodity Futures Trading Commission. Information Regarding Forward-Looking Information The statements in this Annual Report on Form 10-K that are not historical information may be forward looking statements within the meaning of Section 27a of the Securities Act of 1933 and Section 21E of the Securities 10 Exchange Act of 1934. Although we believe that our expectations regarding future events are based on reasonable assumptions, no assurance can be made that our goals will be achieved or that expectations regarding future developments will prove to be correct. Important factors that could cause actual results to differ materially from the expectations reflected in the forward looking statements herein include, but are not limited to, the following: o changes in regulations; o our success in obtaining additional lease barrels; o changes in crude oil production volumes (both world-wide and in areas in which we have operations); o developments relating to possible acquisitions, dispositions or business combination opportunities; o volatility of crude oil prices, P-Plus and grade differentials; o the success of the risk management activities; o credit requirements by the counterparties; o the cost of obtaining liability and property insurance at a reasonable cost; o acts of sabotage, terrorism or other similar acts causing damage greater than our insurance coverage limits; o our ability in the future to generate sufficient amounts of Available Cash to permit the payment to unitholders of a quarterly distribution; o any additional requirements for testing or changes in the Mississippi pipeline system as a result of the oil spill that occurred there in December 1999; o any fines and penalties federal and state regulatory agencies may impose in connection with the oil spill that would not be reimbursed by insurance; o the costs of testing under the IMP and any rehabilitation required as a result of that testing; o estimated timing and amount of future capital expenditures; o our success in increasing tariff rates on our common carrier pipelines; o results of current or threatened litigation; and o conditions of capital markets and equity markets during the periods covered by the forward looking statements. All previous and subsequent written or oral forward looking statements attributable to us, or persons acting on the Partnership's behalf, are expressly qualified in their entirety by the foregoing cautionary statements. Item 2. Properties We own and operate three common carrier crude oil pipeline systems. The pipelines and related gathering systems consist of the 623-mile Texas system, the 103-mile Jay System extending between Florida and Alabama, and the 219-mile Mississippi System extending between Mississippi and Louisiana. The Texas system includes 338 miles of pipe that has been temporary idled. The segments that have been temporary idled are Groesbeck to Hearne, Bryan to Satsuma (in northwest Houston), and Satsuma to Cullen Junction (south Houston). We entered into a joint tariff with Teppco Crude Pipeline Company L.P. to transfer oil to their custody near Satsuma and receive it back from them at Cullen Junction. We own approximately 800,000 barrels of storage capacity associated with the Texas pipeline system. Additionally, we lease approximately 200,000 barrels of storage capacity for the Texas System. We own 200,000 barrels of storage capacity on our Mississippi System, with the tankage spread across the system. The Jay system has 200,000 barrels of storage capacity, primarily at Jay station. In addition to transporting crude oil by pipeline, the Partnership transports crude oil through a fleet of leased tractors and trailers. At December 31, 2002, the trucking fleet consisted of 74 tractor-trailers. The trucking fleet generally hauls the crude oil to one of the approximately 97 pipeline injection stations owned or leased by the Partnership. We lease approximately 27,000 square feet of office space in Houston, Texas, for our corporate office. This lease expires in 2005. 11 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, is not expected to have a material adverse effect on the financial condition or results of operations of the Partnership. See Note 20 of Notes to Consolidated Financial Statements. Item 4. Submission of Matters to a Vote of Security Holders None. PART II Item 5. Market for Registrant's Common Units and Related Security Holder Matters 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. Price Range Cash High Low Distributions(1) 2002 ---------- --------- ---------------- ---- First Quarter..... $ 3.94 $ 2.31 $ - Second Quarter.... $ 4.20 $ 1.80 $ - Third Quarter..... $ 5.75 $ 2.00 $ - Fourth Quarter.... $ 5.00 $ 4.05 $ 0.20 (2) 2001 ---- First Quarter..... $ 6.10 $ 3.50 $ 0.20 Second Quarter.... $ 6.00 $ 4.15 $ 0.20 Third Quarter..... $ 6.92 $ 4.20 $ 0.20 Fourth Quarter.... $ 7.00 $ 2.33 $ 0.20 --------------------- (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, 2002, there were 8,625,000 Common Units outstanding. As of December 31, 2002, there were approximately 10,000 record holders and beneficial owners (held in street name) of the Partnership's Common Units. The Partnership will distribute 100% of its 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 the cash receipts less cash disbursements of the Partnership adjusted for net changes to reserves. The full definition of Available Cash is set forth in the Partnership Agreement and amendments thereto, which is filed as an exhibit hereto. In the fourth quarter of 2000, the Partnership was restructured pursuant to a vote of the Common Unitholders. As a result of this restructuring, the target Minimum Quarterly Distribution ("MQD") was reduced from $0.50 per Common Unit to $0.20 per Common Unit beginning with the distribution for the fourth quarter of 2000. 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. The payment of distributions in the future is dependent upon our ability to generate sufficient Available Cash and whether we would violate covenants in our credit agreement by making such distributions. Should distributions resume, the distribution per common unit will be based upon the Available Cash generated for that quarter, which may be less than $0.20 per unit. See Management's Discussion and Analysis of Financial Condition and Results of Operations - Distributions. Copies of our press releases and our filings with the SEC are available on our website. Our website is www.genesiscrudeoil.com. 12 Item 6. Selected Financial Data The table below includes selected financial data for the Partnership for the years ended December 31, 2002, 2001, 2000, 1999 and 1998 (in thousands, except per unit and volume data). Year Ended December 31, ------------------------------------------------------------------------------ 2002 2001 2000 1999 1998 ------------- ------------- ------------- -------------- -------------- Income Statement Data: Revenues: Gathering & marketing revenues. $ 891,595 $ 3,326,003 $ 4,309,614 $ 2,144,646 $ 2,216,942 Pipeline revenues.............. 20,211 14,195 14,940 16,366 16,533 ------------- ------------- ------------- -------------- -------------- Total revenues............... 911,806 3,340,198 4,324,554 2,161,012 2,233,475 Cost of sales: Crude cost..................... 859,312 3,293,836 4,281,567 2,118,318 2,184,529 Field operating costs.......... 16,451 15,649 13,673 11,669 12,778 Pipeline operating costs....... 12,928 10,897 8,652 8,161 7,971 ------------- ------------- ------------- -------------- -------------- Total cost of sales.......... 888,691 3,320,382 4,303,892 2,138,148 2,205,278 ------------- ------------- ------------- -------------- -------------- Gross margin...................... 23,115 19,816 20,662 22,864 28,197 General and administrative expenses 8,289 11,691 10,942 11,649 11,468 Depreciation and amortization..... 5,813 7,546 8,032 8,220 7,719 Impairment of long-lived assets... - 45,061 - - - Other operating charges........... 1,500 1,500 1,387 - 373 ------------- ------------- ------------- -------------- -------------- Operating income (loss)........... 7,513 (45,982) 301 2,995 8,637 Interest income (expense), net.... (1,035) (527) (1,010) (929) 154 Change in fair value of derivatives (2,094) 2,259 - - - Other income (expense)............ 708 167 1,148 849 28 ------------- ------------- ------------- -------------- -------------- Income (loss) before minority interest and cumulative effect of change in accounting principle 5,092 (44,083) 439 2,915 8,819 Minority interests................ - (4) 258 583 1,763 ------------- ------------- ------------- -------------- -------------- Income (loss) before cumulative effect of change in accounting principle....................... 5,092 (44,079) 181 2,332 7,056 Cumulative effect of change in accounting principle, net of minority interest effect - 467 - - - ------------- ------------- ------------- -------------- -------------- Net income (loss)................. $ 5,092 $ (43,612) $ 181 $ 2,332 $ 7,056 ============= ============= ============= ============== ============== Net income (loss) per common unit- basic and diluted: Income (loss) before cumulative effect of change in accounting principle.................... $ 0.58 $ (5.01) $ 0.02 $ 0.27 $ 0.80 Cumulative effect of change in accounting principle - 0.05 - - - ------------- ------------ ------------- -------------- -------------- Net income (loss).............. $ 0.58 $ (4.96) $ 0.02 $ 0.27 $ 0.80 ============= ============ ============= ============== ============== Cash distributions per common unit: $ 0.20 $ 0.80 $ 2.28 $ 2.00 $ 2.00 Balance Sheet Data (at end of period): Current assets.................... $ 92,830 $ 182,100 $ 350,604 $ 274,717 $ 185,216 Total assets...................... 137,537 230,113 449,343 380,592 297,173 Long-term liabilities............. 5,500 13,900 - 3,900 15,800 Minority interests................ 515 515 520 30,571 29,988 Partners' capital................. 35,302 32,009 82,615 53,585 67,871 Other Data: Maintenance capital expenditures.. $ 4,211 $ 1,882 $ 1,685 $ 1,682 $ 1,509 Volumes (bpd): Gathering and marketing: Wellhead..................... 63,911 84,677 99,602 93,397 114,400 Bulk and exchange............ 37,002 270,845 297,776 242,992 325,468 Pipeline ...................... 75,869 84,686 86,458 94,048 85,594
13 The table below summarizes the Partnership's quarterly financial data for 2002 and 2001 (in thousands, except per unit data). 2002 Quarters --------------------------------------------------------------- First Second Third Fourth ------------ ------------ ------------ ------------ Revenues................................. $ 239,239 $ 240,769 $ 209,916 $ 221,882 Gross margin............................. $ 5,438 $ 6,222 $ 6,268 $ 5,187 Operating income......................... $ 1,927 $ 2,543 $ 1,296 $ 1,747 Net income............................... $ 1,314 $ 2,106 $ 103 $ 1,569 Net income per Common Unit-basic and diluted............................ $ 0.15 $ 0.24 $ 0.01 $ 0.18 2001 Quarters --------------------------------------------------------------- First Second Third Fourth ------------ ------------ ------------ ------------ Revenues................................. $ 930,293 $ 920,879 $ 821,647 $ 667,379 Gross margin............................. $ 4,625 $ 5,791 $ 6,261 $ 3,139 Operating income (loss).................. $ 1 $ 922 $ 1,429 $ (48,334) Net income (loss) before cumulative effect of change in accounting principle.............................. $ 3,404 $ 2,500 $ (267) $ (49,720) Cumulative effect of change in accounting principle, net of minority interest effect................................. $ 467 $ - $ - $ - Net income............................... $ 3,871 $ 2,500 $ (267) $ (49,720) Net income (loss) before cumulative effect of change in accounting principle per Common Unit - basic and diluted................................ $ 0.39 $ 0.28 $ (0.03) $ (5.65) Net income (loss) per Common Unit - basic and diluted $ 0.44 $ 0.28 $ (0.03) $ (5.65)
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: o Highlights of 2002 o Outlook for 2003 and Beyond o Liquidity and Capital Resources o Results of Operations o Other Matters o New Accounting Pronouncements o Critical Accounting Policies Highlights of 2002 We believe that the most important event of 2002 was the sale of our General Partner by Salomon to a subsidiary of Denbury Resources Inc. ("Denbury") on May 14, 2002. Genesis owns and operates a 219-mile pipeline system in Mississippi adjacent to several of Denbury's existing and prospective oil fields. Denbury is the largest oil and natural gas operator in the state of Mississippi. There may be mutual benefits to Denbury and Genesis due to this common production and transportation area. Because of this relationship, we may 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 carbon dioxide (CO2) based tertiary recovery operations, Denbury would expect to add crude oil gathering and CO2 supply infrastructure to these fields. We may be able to provide or acquire this infrastructure and provide support to 14 Denbury's development of these fields. Further, as the fields are developed over time, it may create increased demand for our crude oil transportation services. During 2002, average daily throughput on the Mississippi System where Denbury is a significant source of production near the pipeline increased from approximately 6,000 barrels per day during May, 2002, the month Denbury acquired our general partner, to approximately 9,900 barrels per day during December. We expect this trend of increased throughput on these segments of the system to continue. However, we can make no assurances that such increased throughput will continue or predict that it will increase at this rate. As a result of its acquisition by Denbury, the General Partner, Genesis Energy, Inc. ("Genesis") amended Section 11.2 of the Second Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. ("the Partnership Agreement") to broaden the right of the Common Unitholders to remove the general partner of Genesis Energy, L.P. ("GELP"). 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 are to 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. The amendment was negotiated on behalf of GELP by the audit committee of the board of directors of Genesis. Upon determination of its fairness, including obtaining an opinion from the investment banking firm of the GulfStar Group as to the amendment's fairness to the Common Unitholders of GELP, and an opinion from Delaware legal counsel as to the form of the amendment, the audit committee recommended approval of the amendment to the board of directors of Genesis. During 2002, we reached agreement in principal with the US Environmental Protection Agency (EPA) and the Mississippi Department of Environmental Quality (MDEQ) for the payment of fines under federal and state environmental laws with respect to the Leaf River Spill in December, 1999. See "Other Matters Crude Oil Spill". Based on the discussions leading to this agreement in principal, we have recorded accrued liabilities totaling of $3.0 million during 2001 and 2002. While we are pleased with the progress we have made toward resolving the uncertainty of this environmental liability during 2002, no assurance can be made that we will reach final agreement with the federal and Mississippi governments or the specific terms of a final agreement if one is reached. We successfully completed a major transformation of our gathering and marketing business model during 2002. The primary driver compelling us to change our gathering and marketing business model was the December 31, 2001 replacement of the $300 million Guaranty Facility from Salomon with a $130 million credit facility with Citicorp North America, Inc. See Note 8 to Consolidated Financial Statements and Credit Resources and Liquidity. As a result of this change, we reduced credit support from a daily average of $174.5 million in Salomon guarantees in 2001 to a daily average of $30.2 million in letters of credit from Citicorp. We also reduced the direct cost of trade credit by half from $1.2 million in 2001 to $0.6 million in 2002. To achieve this result, we reduced our average bulk and exchange volumes by 86 percent and our average wellhead volumes by 25 percent from the 2001 levels. We also actively redirected the focus of our lease gathering business to eliminate all volumes that required letters of credit but did not generate sufficient gross margin to support the cost of such credit support. As a result of these and other changes, gathering and marketing gross margin per barrel increased from $0.13 in 2001 to $0.43 in 2002. The financial performance of the gathering and marketing business exceeded our expectations under the new business model. We were pleased to be able to generate gross margin from the gathering and marketing business in 2002 that was 96 percent of the gross margin generated in 2001 while reducing volumes by 72 percent and credit support by 83 percent. We also were able to make permanent reductions to general and administrative expenses of $1.0 million by this change to our business model. As a result of the changes in our business activities described above, we were able to reduce inventory volumes at some locations that had been purchased in prior periods at prices significantly less than the prices at 15 the time we sold those volumes. These volumes had been necessary to ensure efficient and uninterrupted operations in our gathering and marketing activities. Prices for crude oil rose significantly during 2002 as is evidenced by the increase in the price of West Texas Intermediate crude oil (WTI) on the New York Mercantile Exchange (NYMEX), which rose from $20.24 at December 31, 2001 to $31.20 at December 31, 2002. By reducing this inventory in a period of increasing prices we recognized $0.9 million of increased gross margin from the sale of this crude oil. During 2002, we took several steps to improve the profitability of our pipeline operations. Our strategy involved three key initiatives. First, we evaluated our pipeline systems to determine which segments, if any, should be sold, idled or abandoned to reduce cost or risk of operation. Second, we increased our tariffs wherever feasible to achieve an acceptable risk adjusted rate of return. Third, we adjusted our pipeline loss allowances to levels consistent with our peers. We idled or abandoned 338 miles of pipeline on the Texas System during 2002. We expect to sell, idle or abandon more of the Texas System during 2003. While we have made progress evaluating strategic opportunities with respect to the Texas and Jay Systems, these projects are still in progress and we have no substantial information to report at this time. We increased most tariffs on the Texas System by 80 percent effective May 1, 2002. We were pleased that this tariff increase did not result in a significant decrease in volumes on the system. For the Jay System we increased tariffs by 37 percent effective August 1, 2002. For all three systems we increased the pipeline loss allowance that we charge our shippers for assuming the operational risk of volumetric losses from 0.05% to 0.2% effective September 1, 2002. This adjustment placed us in line with most of our peers in the liquids pipeline transportation business. This change is important to us since it reduces the risk of incurring economic loss from operational anomalies and creates some opportunity to profit from operating the pipeline in an effective manner. We developed and implemented a plan during 2002 to place the Mississippi System in condition to handle increased throughput expected from production increases in the area. We implemented operational changes that will allow us to operate much of this pipeline at significantly reduced pressures and will allow us to monitor and evaluate activity on the system in a more effective manner. We also completed the work necessary to restore the segment idled as a result of the 1999 Leaf River Spill. We expect to complete testing and restart this segment early in 2003. Financial results for 2002 were negatively impacted by the effects of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended and interpreted). With the significant reduction in our bulk and exchange activities at December 31, 2001, combined with a review of existing contracts, we determined that we had only one contract meeting the requirement for treatment as a derivative contract under SFAS No. 133 at December 31, 2002. As a result, the fair value of the net asset for derivatives decreased by $2.1 million. During 2002, we did not make a regular quarterly distribution. In December 2001, we obtained a credit facility from Citicorp North America to replace our Guaranty facility and our Credit Agreement with BNP Paribas. See Note 9. This facility, however, includes a provision that does not allow us to pay a distribution for any quarter unless the Borrowing Base under the facility exceeded the usage under the facility for every day of the quarter by at least $20 million plus the total amount of the distribution. For the first and second quarters of 2002, we did not pay distributions as the excess of the Borrowing Base over the usage was less than the required amount. During the third and fourth quarters of 2002, we met the test and were not restricted from making a distribution under the credit facility. However, we did not make a regular quarterly distribution for these periods because of reserves established for future needs of the Partnership. Such future needs include, but are not limited to the payment of fines imposed by regulatory agencies for the December 1999 crude oil spill and future expenditures that will be required for pipeline management integrity programs required by federal regulations. Because some of the Partnership's Unitholders were allocated taxable income for 2002, we did make a special distribution in the amount of $0.20 per unit on December 16, 2002 to Unitholders of record as of December 2, 2002. The amount of taxable income allocated to each unitholder varied, depending on the timing of the unit purchases and the amount of each unitholder's basis in their units. The distribution was made to mitigate the burden of incurring a tax liability without receiving a cash distribution. More detailed discussion of the financial results for 2002 can be found below in "Liquidity and Capital Resources" and "Results of Operations". More detailed discussion of the expectations for restoring the distribution can be found below in "Outlook for 2003 and Beyond." 16 Outlook for 2003 and Beyond Gathering and Marketing Operations The key drivers affecting our gathering and marketing gross margin include production volumes, volatility of P+ margins, volatility of grade differentials, inventory management, and credit costs. A significant factor affecting our gathering and marketing gross margins is changes in the domestic production of crude oil. Short-term and long-term price trends impact the amount of capital that 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. The volatility in prices over the last four 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 by us. Oil prices rose in the latter half of 2002 such that the NYMEX price for WTI was $31.20 at December 31, 2002. International factors such as the strike by oil workers in Venezuela and the potential for war with Iraq as well as domestic influences such as the supply of crude oil in the United States have contributed to the price increase. 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 an individual transaction 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 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. for each month in 2002. Month Average P-Plus WTI Posting ----- -------------- ----------- January $2.7900 $16.5161 February $2.7440 $17.6071 March $2.8520 $21.3306 April $2.8940 $22.9500 May $3.1005 $23.7903 June $3.9100 $22.4500 July $3.0010 $23.7500 August $3.3330 $24.9516 September $3.9860 $26.4750 October $3.2310 $25.6613 November $3.3740 $23.0917 December $3.9130 $26.2177 As can be seen from this table, changes in P-Plus do not necessarily correspond to changes in the market price of oil. 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 who ultimately process the oil. We may buy 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 gross margin from that oil purchase and sale. The table below shows the grade differential 17 between West Texas Intermediate grade crude oil and West Texas Sour grade crude oil for each month of 2002 and the differential between West Texas Intermediate grade crude oil and Light Louisiana Sweet grade crude oil for each month of 2002. WTI/WTS WTI/LLS Month Differential Differential ----- ------------ ------------ January $(1.834) $ 0.260 February $(1.544) $ 0.353 March $(1.231) $ 0.432 April $(1.254) $ 0.358 May $(1.049) $ 0.493 June $(1.352) $(0.581) July $(1.016) $ 0.175 August $(0.812) $ 0.098 September $(1.257) $(0.370) October $(1.666) $(0.167) November $(1.408) $ 0.186 December $(2.243) $(0.008) As can be seen from this table, the WTI/WTS market differential varied from $0.812 in August to $2.243 per barrel in December, 2002. The WTI/LLS market differential varied from a negative $0.581 in June to a positive $0.493 in May 2002. This volatility in grade differentials can affect the volatility of our gathering and marketing gross margins. The 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 and 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 margins from the sale of the crude oil can 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 record a loss in our financial statements should the market price fall below the cost of the inventory. Should market prices rise, then we will experience a gain when we sell the unexpected volume of inventory in a later month at higher prices. We believe we have successfully changed our business model for our gathering and marketing activities to consume less credit support and working capital. We expect this business to continue to perform well during 2003, although not as well as in 2002. Both volumes and margins are expected to be lower during 2003 as this business is likely to be subject to volatility and increased trade credit costs. Additionally, this business may be constrained by the need for trade credit if crude oil prices increase above current levels. During 2003, we expect gathering and marketing gross margins to decline due to an expected decrease in the volume of crude oil to be gathered during 2003. Pipeline Operations As discussed above in "Highlights of 2002", volumes on our pipeline systems declined in 2002. Additionally, operating and maintenance costs increased. For 2003, we expect that volumes may decline in some areas our pipelines serve, but overall average volumes to transport will likely increase from 2002 levels. We also 18 expect to expend funds on additional testing under the integrity management regulations and other large maintenance projects. Volumes on our Texas System averaged 51,987 barrels per day in 2002. We expect that these volumes will decline in 2003 slightly, however the effect of the volume decline on tariff revenues for the year should be mitigated as the increase in tariffs that took effect in May 2002 will be in effect for all of 2003. In 2003, we expect to test the Webster to Texas City segment as well as the Cullen Junction to Webster sections under the integrity management regulations. See discussion of the integrity management regulations in Safety Regulation under in "Item 1. This testing in 2003 is expected to add over $0.3 million to routine operating and maintenance expenses. The results of the testing will likely result in upgrades to the pipeline which we have estimated will cost approximately $3.3 million. Additional discussion of expectations for capital expenditures for the Texas System can be found in Capital Expenditures in "Liquidity and Capital Resources" below. In 2002, we stopped using segments of the Texas System from Bryan to Satsuma and from Satsuma to Cullen Junction. In September, we entered into a joint tariff agreement with Teppco Crude Pipeline Company, L.P. for Teppco to transport oil from Satsuma to Cullen Junction. During 2003, we plan to idle these segments that are no longer in use. To idle a segment of pipeline, we must purge the crude oil in the line and replace it with inert gas. This process will add maintenance costs that we estimate to total less than $0.1 million. We are currently reviewing strategic opportunities for the Texas System. While the tariff increases in 2002 have improved the outlook for this system, we continue to examine opportunities for every part of the system to determine if each segment should be sold, abandoned or invested in for further growth. As part of this examination, we must consider the ability to increase tariffs, which involves reviewing the alternatives available to shippers to move the oil on other pipelines or by truck, production and drilling in the area around the pipeline, the costs to test and improve our pipeline under integrity management regulations, and other maintenance and capital expenditure expectations. The Mississippi System is best analyzed in three segments. The first segment is the portion of the pipeline that begins in Soso, MS and extends to Gwinville, MS where the spill occurred in 1999. We spent $0.6 million in 2002 upgrading the pipeline from Soso to Gwinville. We expect this segment of the pipeline to be fully operational during the first half of 2003. The second segment from Gwinville to Liberty has also been improved to handle the increased volumes produced by Denbury and transported on the pipeline. Volumes on this segment have risen from a low of 3,300 barrels per day in February to almost 10,000 barrels per day in December 2002. In order to handle this higher volume, we have made capital expenditures for tank, station and pipeline improvements and we will need to make more. See Capital Expenditures under "Liquidity and Capital Resources" below. The third segment of the pipeline from Liberty to near Baton Rouge, LA has been out of service since February 1, 2002 while a connecting carrier performs maintenance on its pipeline. The connecting carrier expects to complete their maintenance activities in the second quarter of 2003. At that time we will need to determine if there are sufficient volumes available to be transported on this segment of pipeline to justify the costs to perform the integrity testing and possible upgrading that may be identified in that testing. In 2002, this segment of pipeline contributed $0.1 million to pipeline revenues. In 2001, this segment contributed $1.5 million to pipeline revenues. As discussed above, Denbury is the largest oil and natural 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 carbon dioxide (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. We believe that the highest and best use of the Jay pipeline system in Florida/Alabama would be to convert it to natural gas service. We have entered into strategic alliances with parties in the region to explore this opportunity. 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 2003 or 2004. 19 Pipeline gross margins should decline slightly in 2003. We expect to obtain the benefit of the 2002 tariff increases for the full year 2003 as well as continued increases to throughput. Offsetting these revenue increases will be increased costs for maintenance, insurance and safety. General and Administrative Expenses General and administrative expenses are expected to remain stable. Offsetting permanent cost reductions from the changed business model will be a one-time adjustment for replacing the Citicorp Agreement with a new bank facility with Fleet National Bank as agent, and cost increases for insurance and other costs to comply with SEC regulations mandated by the Sarbanes-Oxley Act. Capital Expenditures An important factor affecting our outlook is capital expenditures. In our 2001 Form 10-K, we indicated that we may need to increase capital expenditures as a result of complying with IMP regulations and other regulatory requirements. Based on our preliminary experience with the IMP program during 2002, we have established a capital budget of $6.7 million for 2003. For 2004, we expect to make capital expenditures of $8.4 million. After 2004, capital expenditures are expected to return to a normal pattern of approximately $2.0 million per year. Access to Capital In the first quarter of 2003, we replaced the credit facility from Citicorp North America, Inc. ("Citicorp Agreement") with a three-year $65 million revolving loan and letter of credit facility with Fleet National Bank as agent ("Fleet Agreement"). The Fleet Agreement has terms similar to the terms in the Citicorp Agreement. The details of those terms are described more fully below in "Liquidity and Capital Resources". The main differences from the Citicorp Agreement are as follows: (a) the new facility permits us to make acquisitions of assets that are used in our existing business; (b) the new facility does not have the $3.0 million limitation on capital expenditures per year and (c) the new facility includes a restriction on our ability to make distributions that requires a difference of $10 million between the borrowing base and utilization of the facility plus distributions, as measured once each month. In the Citicorp Agreement, the borrowing base had to exceed utilization (working capital borrowings plus outstanding letters of credit) plus the amount of the distribution by $20 million every day of the quarter in order for us to make a distribution. As a result of the replacement of the Citicorp Agreement, the unamortized fees paid in December 2001 to obtain the Citicorp Agreement will be charged to expense in the first quarter of 2003. The amount of fees to be charged to expense is $0.6 million. Our outlook will also be impacted by our access to capital for growth. In March 2003, we entered into the $65 million three-year revolving credit facility led by Fleet Bank to replace our existing facility. The combination of obtaining this new facility and our relationship with Denbury should improve our ability to grow the business. However, based on our experience in obtaining this facility, we believe that it will be important for us to further strengthen our balance sheet and improve our financial metrics to be able to improve our access to significant capital for growth. Distribution Expectations 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. As stated above, we made no regular distribution during 2002. We made no distribution with respect to the first two quarters of 2002 because of a restrictive covenant in our credit facility with Citicorp. We made no regular distribution for the third and fourth quarters as we added to reserves for the future needs of the Partnership. We did make a special distribution to our Unitholders in December 2002, to mitigate the burden of incurring a tax liability without receiving a cash distribution. During 2002 we generated $11.8 million of Available Cash before reserves, required debt payments and the special distribution. During 2003, we expect Available Cash before distributions to be less. We expect to resume regular quarterly distributions during 2003 with an anticipated first quarter distribution of at least $0.05 per unit on May 15, 2003, to unitholders of record as of April 30, 2003. Based on the need for larger than normal capital expenditures to comply with the pipeline regulations during 2003 and 2004 and the need to strengthen our balance sheet to improve our access to capital for growth, and considering the restrictive covenant in our new credit facility, we do not expect to restore the regular distribution to the targeted minimum 20 quarterly distribution amount of $0.20 per quarter for the next year or two. 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. Liquidity and Capital Resources Cash Flows During 2002, we generated cash flows from operating activities of $7.4 million as compared to $16.8 million for 2001. In 2002, we reduced our current liabilities by $87.5 million while our current assets declined by $89.3 million. In 2001, we reduced our current liabilities by $159.3 million while our current assets declined by $168.5 million. Factors related to the timing of cash receipts and payments related to the bulk and exchange business were the primary reasons for the fluctuation in our current assets and liabilities in these periods. Cash flows used in investing activities in 2002 were $2.0 million as compared to $1.4 million in 2001. 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. These seats had become surplus assets when the business model was changed to reduce bulk and exchange activities, reducing the level of NYMEX activity that Genesis would need. 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 the 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. Net cash expended for financing activities was $10.2 million in 2002 as compared to $15.1 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 As discussed above, we expended $4.2 million in 2002 for property and equipment. We spent $1.8 million for capital expenditures on the Mississippi Pipeline System, $1.6 million on the Texas Pipeline System, and $0.8 million for computer hardware, software, communication and other technological equipment used for pipeline and trucking operations. The $1.8 million spent for the Mississippi Pipeline System was for two purposes. First, we made improvements to the pipeline from Soso to Gwinville where the crude oil spill had occurred in December 1999 to restore this segment to service. This project was part of the IMP program discussed below. Second, we improved the pipeline from Gwinville to Liberty to be able to handle increased volumes on that segment by adding tankage and making other improvements to station equipment. In Texas, we upgraded the West Columbia segment of the pipeline and improved station equipment. 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 a High Consequence Area. The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology. A High Consequence Area (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 by March 31, 2002, that details 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 21 assessed in the first three and one-half years. Reassessment is then required every five years. We expect to spend $1.0 million in 2003 and $0.1 million in 2004 for pipeline integrity testing that will be charged to pipeline operating expense as incurred. As testing is complete, we are required to take prompt remedial action to address all 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, we have estimated capital expenditures to be made during the IMP assessment period from 2002 through 2009. These capital expenditure projections are based on very preliminary data regarding the cost of rehabilitation. Such capital expenditure projections will be updated as improved data is obtained. During 2002, $1.7 million of the $4.2 million in capital expenditures were for rehabilitation of the Mississippi and Texas Pipeline Systems. Based on actual experience during 2002 applied to our written IMP plan, we expect to spend significant amounts in 2003 and 2004 for capital expenditures. In 2003, we estimate our capital expenditures will be approximately $8.0 million. We expect $4.1 million of the $8.0 million will be spent for capital improvements to our pipeline systems as result of the IMP assessments. Of the remaining $3.9 million in capital expenditures, substantially all of it will be spent on other pipeline improvements such as tankage, equipment upgrades, and corrosion control. In 2004, we expect the level of capital expenditures to be approximately $8.3 million with $4.6 million for pipeline integrity improvements and the balance of $3.5 million for tankage and other improvements. At the end of 2004, we expect that we will have incurred most of the significant costs related to the IMP regulatory compliance and expect to only spend $1.8 million in 2005 for capital items, with $1.2 million related to IMP. Expenditures in years after 2006 should remain in the $1.5 million to $2.5 million level as the expected integrity improvements should not be as great on the segments of the pipelines with the lower 50% risk. Capital Resources In December 2001, we entered into a two-year $130 million Senior Secured Revolving Credit Facility ("Citicorp Agreement") with Citicorp to provide letters of credit and working capital borrowings. In May 2002, we elected, under the terms of the Citicorp Agreement, to amend the Citicorp Agreement to reduce the maximum facility amount to $80 million. The Citicorp Agreement contains a sublimit for working capital loans of $25 million with the remainder available for letters of credit to support crude oil purchases. In March 2003, we replaced our Citicorp Agreement with a $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Agreement"). The Fleet Agreement 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 Agreement are as follows: o Letter of credit fees are based on the Applicable Usage Level ("AUL") and will range from 2.00% to 3.00%. During the first six months of the facility, the rate will be 2.50%. The AUL is a function of the facility usage to the borrowing base on that day. o The interest rate on working capital borrowings is also based on the AUL and allows for loans 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%. During the first six months of the facility, the rate will be the Libor rate plus 2.50%. o We will pay a commitment fee on the unused portion of the $65 million commitment. This commitment fee is also based on the AUL and will range from 0.375% to 0.50%. During the first six months of the facility, the commitment fee will be 0.50%. o 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 (as defined in the Fleet Agreement) generally includes our cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly. 22 o Collateral under the Fleet Agreement consists of our accounts receivable, inventory, cash accounts, margin accounts and property and equipment. o The Fleet Agreement contains covenants requiring a Current Ratio (as defined in the Fleet Agreement), a Leverage Ratio (as defined in the Fleet Agreement), a Cash Flow Coverage Ratio (as defined in the Fleet Agreement), a Funded Indebtedness to Capitalization Ratio (as defined in the Fleet Agreement), Minimum EBITDA, and limitations on distributions to Unitholders. Under the Citicorp Agreement, distributions to Unitholders and the General Partner could only be made if the Borrowing Base exceeded the usage (working capital borrowings plus outstanding letters of credit) under the Citicorp Agreement for every day of the quarter by at least $20 million plus the distribution. Under the Fleet Agreement, this provision is changed to require that the Borrowing Base exceed the usage under the Fleet Agreement by at least $10 million plus the distribution measured once each month. See additional discussion below under "Distributions". At December 31, 2002, we had $5.5 million outstanding under the Citicorp Agreement. Due to the revolving nature of loans under the Citicorp Agreement, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of December 31, 2003. At December 31, 2002, we had letters of credit outstanding under the Citicorp Agreement totaling $26.3 million, comprised of $13.8 million and $12.5 million for crude oil purchases related to December 2002 and January 2003, respectively. As a result of our decision to reduce the level of bulk and exchange transactions, credit support in the form of letters of credit has been less in 2002 than it was in 2001. However, any significant decrease in our financial strength, regardless of the reason for such decrease, may increase the number of transactions requiring letters of credit, which could restrict our gathering and marketing activities due to the limitations of the Fleet Agreement and Borrowing Base. This situation could in turn adversely affect our ability to maintain or increase the level of our purchasing and marketing activities or otherwise adversely affect our profitability and Available Cash. Working Capital Our balance sheet reflects negative working capital of $3.5 million. The majority of this difference can be attributed to the accrual for the fines and penalties that we expect to pay to state and federal regulators related to the December 1999 Mississippi oil spill. That accrual is $3.0 million. As we have a working capital sublimit under the Fleet Agreement of $25 million and have only borrowed $5.5 million at December 31, 2002, we have the ability to borrow the funds to make the necessary payments. Contractual Obligation and Commercial Commitments In addition to the Citicorp Agreement discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil. The table below summarizes these obligations and commitments at December 31, 2002 (in thousands). Payments Due by Period ----------------------------------------------------------------------- Less than 1 - 3 4 - 5 After 5 Contractual Cash Obligations Total 1 Year Years Years Years ---------------------------- ------------ ------------ ----------- ------------ ------------ Operating Leases......... $ 15,630 $ 4,128 $ 7,057 $ 1,927 $ 2,518 Unconditional Purchase Obligations (1) 139,852 138,918 934 - - ------------ ------------ ----------- ------------ ------------ Total Contractual Cash Obligations $ 155,482 $ 143,046 $ 7,991 $ 1,927 $ 2,518 ============ ============ =========== ============ ============ (1) The unconditional purchase obligations included above are contracts to purchase crude oil, generally at market-based prices. For purposes of this table, market prices at December 31, 2002, were used to value the obligations, such that actual obligations may differ from the amounts included above.
Distributions The Partnership Agreement for Genesis Energy, L.P. provides that 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 23 Cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. (A full definition of Available Cash is set forth in the Partnership Agreement.) The Partnership Agreement indicates that the target minimum quarterly distribution ("MQD") for each quarter is $0.20 per unit. Under the terms of the Citicorp Agreement, we could not pay a distribution for any quarter unless the Borrowing Base exceeded the usage under the Citicorp Agreement (working capital loans plus outstanding letters of credit) for every day of the quarter by at least $20 million plus the total amount of the distribution. For the first and second quarters of 2002, we did not pay a distribution as the excess of the Borrowing Base over the usage dropped below the required total. During the third quarter of 2002, we met this test and thus were not restricted from making a distribution under the Citicorp Agreement. However, we did not make a distribution for the third quarter of 2002 because of a reserve established for future needs of the Partnership. These reserves exceeded Available Cash for the third quarter of 2002. Similarly, we did not make a regular distribution for the fourth quarter of 2002 as reserves again exceeded Available Cash. Such future needs of the Partnership include, but are not limited to, the fines that are being imposed in connection with the crude oil spill that occurred on the Mississippi System in December 1999 and future expenditures that will be required for pipeline integrity management programs required by federal regulations that are described above under "Capital Expenditures". Available cash before reserves for the year ended December 31, 2002, is as follows (in thousands): Net income................................................... $ 5,092 Depreciation and amortization................................ 5,813 Increase to environmental accrual............................ 1,500 Change in fair value of derivatives.......................... 2,094 Net gain from asset sales.................................... 1,535 Maintenance capital expenditures............................. (4,211) ----------- Available Cash before reserves............................... $ 11,823 Special distribution paid in December 2002................... (1,760) Reduction of debt required in 2002 as a result of asset sales (2,171) ----------- Remaining Available Cash before reserves..................... $ 7,892 =========== As discussed above in Outlook for 2003 and Beyond above, we expect to resume regular quarterly distributions during 2003 of at least $0.05 per unit. Any decision to restore the distribution to the targeted minimum quarterly distribution will take into account our ability to sustain the distribution on an ongoing basis with cash generated by our existing asset base, capital requirements needed to maintain and optimize the performance of our asset base, and our ability to finance our existing capital requirements and accretive acquisitions. For each of the first three quarters of 2001, the Partnership paid a distribution to the Common Unitholders and the General Partner of $0.20 per unit. Some of the Partnership's Unitholders were allocated taxable income for 2002. The amount of taxable income allocated to each unitholder varied, depending on the timing of unit purchases and the amount of each unitholder's tax basis in their units. In order to mitigate the burden of incurring a tax liability without receiving a cash distribution, we made a special distribution in the amount of $0.20 per unit on December 16, 2002 to Unitholders of record as of December 2, 2002. Industry Credit Market Disruptions Over the last eighteen months there have been an unusual number of business failures and large financial restatements by small as well as large companies in the energy industry. Because the energy industry is very credit intensive, these failures and restatements have focused attention on the credit risks of companies in the energy industry by credit rating agencies, producers and counterparties. This focus on credit has affected us in two ways - requests for credit from producers and extension of credit to counterparties. While we have seen some increase in requests for credit support from producers (primarily in the first quarter of 2002), we have been relatively successful in obtaining open credit from most producers. Because we are an aggregator of crude oil, sales of crude oil tend to be large volume transactions. In transacting business with our counterparties, we must decide how much credit to extend to each counterparty, as well as the form and amount of financial assurance to obtain from counterparties when credit is not extended. 24 We have modified our credit arrangements with certain counterparties that have been adversely affected by recent financial difficulties in the energy industry. 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 $80.7 million aggregate receivables on our consolidated balance sheet at December 31, 2002, approximately $79.9 million, or 99%, were less than 30 days past the invoice date. FERC Notice of Proposed Rulemaking On August 1, 2002, the Federal Energy Regulatory Commission ("FERC") issued a Notice of Proposed Rulemaking that, if adopted, would amend its Uniform System of Accounts for public utilities, natural gas companies and oil pipeline companies by requiring specific written documentation concerning the management of funds from a FERC-regulated subsidiary by a non-FERC-regulated parent. Under the proposed rule, as a condition for participating in a cash management or money pool arrangement, the FERC-regulated entity would be required to maintain a minimum proprietary capital balance (stockholder's equity) of 30 percent, and the FERC-regulated entity and its parent would be required to maintain investment grade credit ratings. If either of these conditions is not met, the FERC-regulated entity would not be eligible to participate in the cash management or money pool arrangement. This proposed rule was subject to a comment period of 15 days after its publication in the Federal Register. A significant number of comments were received by the FERC. Hearings have been held by the FERC and industry organizations have submitted suggestions of changes to the proposed rule. At this time, it is unclear when, or if, the rule will be enacted. We believe that, if enacted as proposed, this rule may affect the manner in which we manage our cash; however, we are unable to predict the full impact of this proposed regulation on our business. Results of Operations The following review of the results of operations and financial condition should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Selected financial data for this discussion of the results of operations follows, in thousands. Years Ended December 31, ----------------------------------------------- 2002 2001 2000 ------------ ----------- ------------ Revenues Gathering & marketing....................... $ 891,595 $ 3,326,003 $ 4,309,614 Pipeline.................................... $ 20,211 $ 14,195 $ 14,940 Gross margin Gathering & marketing....................... $ 15,832 $ 16,518 $ 14,374 Pipeline.................................... $ 7,283 $ 3,298 $ 6,288 General and administrative expenses............. $ 8,289 $ 11,691 $ 10,942 Depreciation and amortization................... $ 5,813 $ 7,546 $ 8,032 Impairment of long-lived assets................. $ - $ 45,061 $ - Other operating charges......................... $ 1,500 $ 1,500 $ 1,387 Operating income (loss)......................... $ 7,513 $ (45,982) $ 301 Interest income (expense), net.................. $ (1,035) $ (527) $ (1,010) Change in fair value of derivatives............. $ (2,094) $ 2,259 $ - Cumulative effect of adoption of FAS 133........ $ - $ 467 $ - Net gain on disposal of surplus assets.......... $ 708 $ 167 $ 1,148
25 Our profitability depends to a significant extent upon our ability to maximize gross margin. Gross 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 gross 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 gross 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 gross 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. We generally enter into exchange transactions 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. Year Ended December 31, 2002 Compared with Year Ended December 31, 2001 Gross margin. Gathering and marketing gross margins decreased $0.7 million or 4% to $15.8 million for the year ended December 31, 2002, as compared to $16.5 million for the year ended December 31, 2001. The factors affecting gross margin were: o an increase in gross margin of $22.4 million 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; o a 72 percent decrease in wellhead, bulk and exchange purchase volumes between 2001 and 2002, resulting in a decrease in gross margin of $23.9 million; o a decrease of $0.7 million in credit costs primarily due to the reduction in bulk and exchange transactions; o a $0.9 million increase in gross margin in the 2002 period as a result of the sale of crude oil that is no longer needed to ensure efficient and uninterrupted operations; and o an increase of $0.8 million in field operating costs, primarily from a $0.4 million increase in payroll and benefits, a $0.3 million increase in repair costs, and a $0.1 million increase in insurance costs. The increased payroll-related costs and fuel costs can be attributed to an approximate 12 percent increase in the miles driven in our trucks. 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 the Partnership's loss history. As discussed previously, 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 were the primary reasons gathering and marketing volumes decreased by 72%. Pipeline gross margin increased $4.0 million or 121% to $7.3 million for the year ended December 31, 2002, as compared to $3.3 million for the year ended December 31, 2001. The factors affecting pipeline gross margin were: 26 o an increase in revenues from sales of pipeline loss allowance barrels of $2.3 million 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; o an increase of 43 percent in the average tariff on shipments resulting in an increase in revenue of $5.1 million; o a decrease in throughput of 10 percent between the two years, resulting in a revenue decrease of $1.4 million; and o an increase in pipeline operating costs of $2.0 million 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, and for other operating costs, offset by reduced power costs and 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 $0.3 million. Tank and station maintenance expenses increased $0.2 million. In 2002, we increased safety training for our pipeline operations personnel at a cost of $0.2 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 $0.5 million. Insurance costs increased by $0.4 million due to the combination of insurance market conditions and our loss history. Other operating costs, including corrosion control and tank rentals, increased by $0.5 million. Power costs were lower by $0.2 million due to electricity deregulation in Texas. Our remote monitoring and control costs were lower by $0.3 million as we completed the transition in early 2002 from a more expensive service. 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 generaland 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 and amortization. Depreciation and amortization expense decreased $1.7 million in 2002 from the 2001 level. As a result of the impairment of the pipeline assets in 2001, the value to be depreciated was reduced. Other operating charge. 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 income (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 the Credit Agreement with Citicorp. From January 1, 2002, until May 3, 2002, that facility maximum was $130 million. At May 3, 2002, the Credit Agreement was reduced to a maximum of $80 million. The larger amount of the credit facility resulted in substantially higher commitment fees in 2002. 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 do 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 for the nine months ended September 30, 2002. 27 At December 31, 2002, the only contracts qualifying as a derivative under SFAS No. 133 were a cash flow hedge of inventory. The change in the fair value of these contracts at December 31, 2002 was a loss of $39,000, which is reflected as a reduction of consolidated comprehensive income. The consolidated balance sheet includes $39,000 in other current liabilities as a result of recording the fair value of derivatives. The fair value of our derivative contracts at December 31, 2002, was determined using the sources for fair value as shown in the table below (in thousands). Fair Value of Contracts at Period-End Maturity Maturity Maturity in less than 3-6 Excess of Total Source of Fair Value 3 Months Months 6 Months Fair Value -------------------- -------- ------ -------- ---------- Prices actively quoted................. $ 39 $ - $ - $ 39 Prices provided by other external sources - - - - Prices based on models and other valuation methods.................... - - - - --------- ------ -------- ---------- Total.................................. $ 39 $ - $ - $ 39 ========= ====== ======== ==========
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 and a building and surplus used vehicles resulting in additional cumulative net gains of $0.2 million. In 2000, we made the decision to lease 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. Year Ended December 31, 2001 Compared with Year Ended December 31, 2000 Gross margin. Gathering and marketing gross margins increased $2.1 million or 15% to $16.5 million for the year ended December 31, 2001, as compared to $14.4 million for the year ended December 31, 2000. The factors affecting gross margin were: o a 23 percent 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, which increased gross margin by $6.3 million; o a decrease of 11% percent in wellhead, bulk and exchange purchase volumes between 2000 and 2001, resulting in a decrease in gross margin of $3.3 million; o a decrease of $0.5 million in credit costs primarily due to a 15 percent decrease in the average absolute price level of crude oil and the decrease in purchase volumes; and o an increase of $2.0 million in field operating costs, primarily from a $2.2 million increase in rental costs due to the replacement of the tractor/trailer fleet with a leased fleet in the fourth quarter of 2000, a $0.2 million increase in payroll and benefits, and a $0.1 million increase in insurance costs, offset by $0.5 million decrease in repair costs. The increased payroll-related costs and fuel costs can be attributed to an approximate 4% increase in the number of barrels transported by the Partnership in trucks. The increased insurance costs reflect a combination of changes in the insurance market and the Partnership's loss history. The decline in repair costs is attributable to the change to the use of leased vehicles under a full-service maintenance lease. In addition, gross margin in 2000 included an unrealized loss on written option contracts of $0.6 million. In the latter half of 2001, Genesis began making changes to its business operations to prepare for the change from the $300 million Guaranty Facility with Salomon to a smaller letter of credit facility. These changes resulted in a substantial decrease in the Partnership's bulk and exchange activity due to the relatively low margins and high credit requirements on these transactions. Additionally, the Partnership began reviewing its wellhead purchase 28 contracts to determine whether margins under those contracts would support higher credit costs. In some cases, contracts were cancelled. These volume reductions were the primary reasons gathering and marketing volumes decreased by 11%. See "Outlook" below for additional discussion of these changes to business operations. Pipeline gross margin decreased $3.0 million or 48% to $3.3 million for the year ended December 31, 2001, as compared to $6.3 million for the year ended December 31, 2000. Pipeline revenues declined $0.4 million as a result of small declines in throughput and average tariffs. Revenues from sales of pipeline loss allowance barrels decreased $0.4 million as a result of lower crude prices. Pipeline operating costs were $2.2 million higher in the 2001 period primarily due to a $1.3 million increase in maintenance costs, a $0.3 million increase in insurance costs, a $0.2 million increase in payroll and related benefits and a $0.4 increase in general operating costs. The increased insurance costs reflect the combination of changes in the insurance market and the Partnership's loss history. General and administrative expenses. General and administrative expenses increased $0.7 million in 2001 from the 2000 level. In 2001, the Partnership's costs for professional services and contract labor increased $0.7 million, primarily as a result of the proposed sale of the general partner and related legal and consulting costs. See "Termination of Proposed General Partner Sale" below. Also contributing to the increase in general and administrative costs was a $0.4 million increase in salaries and benefits and $0.7 million of severance costs incurred as a result of a reduction in personnel. The number of personnel was reduced to reflect the reduced bulk purchases planned by the Partnership, as well as the overall decline in operating income. Offsetting the increases that total $1.8 million was a reduction in expenses of $1.1 million related to the Restricted Unit Plan. Depreciation and amortization. Depreciation and amortization expense decreased $0.5 million in 2001 from the 2000 level. This decrease is primarily attributable to the sale in the last quarter of 2000 of the Partnership's tractor/trailer fleet, thereby reducing depreciation, combined with the completion of depreciation on assets of the Partnership that had reached the end of their depreciable lives. Impairment of long-lived assets. As a result of declining revenues and significant increases in costs for operations and maintenance combined with regulatory changes requiring additional testing for pipeline integrity, the Partnership determined that its estimated undiscounted future cash inflows from the pipeline assets is less than the carrying value of those assets. As a result, the Partnership wrote the assets down to their estimated fair value in accordance with Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of" (FAS 121). An impairment charge of $45.0 million was recorded, with $38.0 million recorded to accumulated depreciation of the pipeline assets and $7.0 million recorded to accumulated amortization of goodwill. Other operating charge. In 2001, the Partnership recorded a charge of $1.5 million related to environmental matters, including the Mississippi spill that occurred in December 1999. In 2000, other operating charges included $1.4 million of costs related to the restructuring of the Partnership in December 2000. This $1.4 million of costs consisted primarily of legal and accounting fees, financial advisor fees, proxy solicitation expenses and the costs to print and mail a proxy statement to Common Unitholders. Interest income (expense), net. In 2001, the Partnership had a decrease in its net interest expense of $0.5 million. Interest expense decreased $0.6 million and interest income decreased $0.1 million. Average daily debt outstanding declined by $6.8 million, resulting in the decrease in interest expense. Interest income decreased primarily as a result of lower interest rates. Change in fair value of derivatives. The Partnership utilizes crude oil futures contracts and other financial derivatives to reduce its exposure to unfavorable changes in crude oil prices. On January 1, 2001, the Partnership 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. SFAS No. 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Under SFAS No. 133, the Partnership marks to fair value all of its derivative instruments at each period end with changes in fair value 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. In general, SFAS No. 133 requires that at the date of initial adoption, the difference between the fair value 29 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 the Partnership's 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. Net gain on disposal of surplus assets. In 2000, management of the General Partner made the decision to lease its tractor/trailer fleet from Ryder Transportation Services. The majority of the existing fleet was sold, resulting in cash proceeds of $0.4 million and a gain of $0.1 million in 2001 and proceeds of $1.8 million and a net gain of $1.0 million in 2000. The Partnership sold additional surplus assets, which resulted in proceeds of $0.1 million and a gain of $0.1 million in 2000. Other Matters Crude Oil Contamination The Partnership was 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") seeks 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 claims the fire and explosion was caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. We believe that the suit is without merit and intend to vigorously defend ourselves in this matter. We believe that any potential liability will be covered by insurance. 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. We believe that any potential liability will substantially be covered by insurance. 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 affect 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, 30 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 is effective for Genesis on January 1, 2003. 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 expiration of the lease term. For our pipelines, we expect that we will be 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. 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 shall be applied in fiscal years beginning after May 15, 2002. The provisions related to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002. All other provisions shall be 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 In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. The impact that SFAS No. 146 will have on our consolidated financial statements will depend on the circumstances of any specific exit or disposal activity. Interpretation No. 45 In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others". 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 initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in this interpretation are effective for financial statements of interim or annual periods after December 15, 2002. 31 SFAS 148 In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," which provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002, and financial reports containing condensed financial statements for interim periods beginning after December 15, 2002. At this time, there are no outstanding grants of Partnership units under our Restricted Unit Plan (see Note 15). Therefore, we do not believe that the adoption of this statement will have a material effect on either our financial position, results of operations, cash flows or disclosure requirements. 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. The critical accounting policies and estimates that we have identified are discussed below. Depreciation, Amortization and Impairment of Long-Lived Assets We calculate depreciation and amortization based on useful lives estimated at the time the assets are placed in service. Events in future periods, 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 compare the carrying value of the fixed asset to the estimated undiscounted future cash flows from that asset. Should the undiscounted future cash flows be less than the carrying value, we record an impairment charge to reflect the asset at fair value. Fair value is determined by discounting the future estimated cash flows. Determination as to whether and how much an asset is impaired involves numerous management estimates. Impairment reviews and calculations are based on assumptions that are consistent with our business plans. In 2001, we recorded an impairment charge to our pipeline assets and goodwill totaling $45.1 million. Additionally we adjusted the remaining useful lives of our pipeline assets to be consistent with the determination of the period of time when we would expect future estimated cash flows from the assets. Revenue and Expense Accruals We routinely make accruals for both revenues and expenses due to the timing of compiling billing information, receiving third party information and reconciling our records with those of third parties. Additionally the provisions of SFAS No. 133, require estimates to 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 base these estimates on information obtained from third parties and our 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. Liability and Contingency Accruals We accrue reserves for contingent liabilities including, but not limited to, 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. Based on new information obtained in meetings with regulators, this estimate was increased to a total of $3.0 million in 2002. 32 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 affect on future contractual commitments. We utilize NYMEX commodity based futures contracts and forward contracts to hedge its exposure to these market price fluctuations. We believe the hedging program has been effective in minimizing overall price risk. At December 31, 2002, we used futures contracts exclusively in its hedging program with the latest contract being settled in February 2003. Information about these contracts is contained in the table set forth below. Sell (Short) Buy (Long) Contracts Contracts Crude Oil Inventory ----------- ------------ Volume (1,000 bbls)............................. 128 Carrying value (in thousands)................... $ 3,612 Fair value (in thousands)....................... $ 4,163 Commodity Future Contracts: Contract volumes (1,000 bbls)................... 96 Weighted average price per bbl..................$ 30.79 Contract value (in thousands)...................$ 432 Mark-to-market change (in thousands)............$ (39) ----------- Market settlement value (in thousands)..........$ 393 =========== The table above presents notional amounts in barrels, the weighted average contract price, total contract amount in U.S. dollars and the market settlement value amount in U.S. dollars. The market settlement value was determined by using the notional amount in barrels multiplied by the December 31, 2002 closing prices of the applicable NYMEX futures contract adjusted for location and grade differentials, as necessary. 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 43. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures On May 2, 2002, the Board of Directors and its audit committee dismissed Arthur Andersen LLP as our independent public accountants and engaged Deloitte & Touche LLP to serve as our independent auditors for the fiscal year ending December 31, 2002. Arthur Andersen's report on our consolidated financial statements for the fiscal years ended December 31, 2001 and December 31, 2000, did not contain any adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty or audit scope. In addition, there were no modifications as to accounting principles except that the most recent audit report of Andersen contained an explanatory paragraph with respect to the change in the method of accounting for derivative instruments effective January 1, 2001, as required by the Financial Accounting Standards Board. During the fiscal years ended December 31, 2001 and December 31, 2000, and through the date of the Board of Director's decision, there were no disagreements with Arthur Andersen on any matter of accounting principle or practice, financial statement disclosure, or auditing scope or procedure which, if not resolved to Arthur Andersen's satisfaction, would have caused them to make reference to the subject matter in connection with their reports on our consolidated financial statements for such years; and there were no reportable events, as described in Item 304(a)(1)(v) of Regulation S-K. During the fiscal years ended December 31, 2001 and December 31, 2000, and through the date of the Board of Director's decision, we did not consult Deloitte & Touche LLP with respect to the application of accounting 33 principles to a specified transaction, with completed or proposed, or the type of audit opinion that might be rendered on our consolidated financial statements, or any other matters or reportable events described in Items 304(a)(2)(i) and (ii) or Regulation S-K. Part III 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 consists of eight persons. Four of the directors, including the Chairman of the Board, are executives of Denbury. Our Chief Exceutive Officer serves on the Board of Directors. The three remaining directors are independent of Genesis and Denbury or any of its affiliates. The Board of Directors of the General Partner has established a committee (the "Audit Committee") consisting of the independent directors. The committee has the authority to review, at the request of the General Partner, specific matters as to which the General Partner believes there may be a conflict of interest in order to determine if the resolution of such conflict is fair and reasonable to the Partnership. In addition, the committee reviews our external financial reporting, recommends engagement of our independent accountants, and reviews the adequacy of our internal accounting controls. 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. Name Age Position ------------------------------ --- --------------------------------------- Gareth Roberts................ 50 Director and Chairman of the Board Mark J. Gorman................ 48 Director, Chief Executive Officer and President Ronald T. Evans............... 40 Director Herbert I. Goodman............ 80 Director Susan O. Rheney............... 43 Director Phil Rykhoek.................. 46 Director J. Conley Stone............... 71 Director Mark A. Worthey............... 45 Director Ross A. Benavides............. 49 Chief Financial Officer, General Counsel and Secretary Kerry W. Mazoch............... 56 Vice President, Crude Oil Acquisitions Karen N. Pape................. 45 Vice President and Controller 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 Vice President of Reservoir Engineering of Denbury and has served in that capacity since September 1999. Before joining Denbury, Mr. Evans was employed in a similar capacity with Matador Petroleum Corporation for three years and employed by Enserch Exploration, Inc. for twelve years in various positions. Herbert I. Goodman was elected to the Board of Directors of the General Partner in 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. From 1988 until 1996 he was Chairman and Chief Executive Officer of Applied Trading Systems, Inc., a trading and consulting business. 34 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., where she serves on the audit and finance committees, American Plumbing and Mechanical, Inc., where she serves on the audit and compensation committees and Mail-Well, Inc. Phil Rykhoek has served as a director of the General Partner since May 2002. Mr. Rykhoek is Chief Financial Officer, Vice President, Secretary and Treasurer of Denbury, and has served in those capacities since 1995. J. Conley Stone was elected to the Board of Directors of the General Partner in 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 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. He served as Tax Counsel for Lyondell Petrochemical Company ("Lyondell") from May 1997 to October 1998. Prior to joining Lyondell, he was Vice President of Basis Petroleum Corporation. 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. 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 New York 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 2002 its officers and directors complied with all applicable filing requirements in a timely manner. The three independent directors receive an annual fee of $30,000. The Audit Committee Chairman receives an annual fee of $4,000 and all members of the Audit Committee receive $1,500 for attendance at committee meetings. Beginning in 2003, Denbury will receive $120,000 from the Partnership for providing four of its executives as directors. Mr. Gorman does not receive a fee for his service as a director. Item 11. Executive 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." The following table summarizes certain information regarding the compensation paid or accrued by Genesis during 2002, 2001, and 2000 to the Chief Executive Officer and each of our three other executive officers (the "Named Officers"). 35 Summary Compensation Table Long-Term Annual Compensation Compensation Awards Other Annual Restricted All Other Salary Bonus Compensation Stock Awards Compensation Name and Principal Position Year $ $ $ (1) $ $ ------------------------------- ---- --------- ------- ------------ ------------ ----------- Mark J. Gorman 2002 270,000 5,193 - - 11,500 (2) Chief Executive Officer 2001 270,000 56,814 - - 10,200 (3) and President 2000 270,000 50,000 - - 10,200 (3) Ross A. Benavides 2002 180,000 3,462 - - 11,500 (2) Chief Financial Officer, 2001 175,000 54,785 - - 10,200 (3) General Counsel and 2000 150,000 50,000 - - 9,173 (4) Secretary Kerry W. Mazoch 2002 170,000 3,270 - - 11,478 (5) Vice President, Crude 2001 169,000 30,720 - - 10,200 (3) Oil Acquisitions 2000 166,000 30,000 - - 10,080 (6) Karen N. Pape 2002 136,000 2,616 - - 10,118 (7) Vice President and Controller (1) No Named Officer had "Perquisites and Other Personal Benefits" with a value greater than the lesser of $50,000 or 10% of reported salary and bonus. (2) Includes $5,500 of Company-matching contributions to a defined contribution plan and $6,000 of profit-sharing contributions to a defined contribution plan. (3) Includes $5,100 of Company-matching contributions to a defined contribution plan and $5,100 of profit-sharing contributions to a defined contribution plan. (4) Includes $4,587 of Company-matching contributions to a defined contribution plan and $4,586 of profit-sharing contributions to a defined contribution plan. (5) Includes $5,500 of Company-matching contributions to a defined contribution plan and $5,978 of profit-sharing contributions to a defined contribution plan. (6) Includes $4,980 of Company matching contributions to a defined contribution plan and $5,100 of profit-sharing contributions to a defined contribution plan. (7) Includes $5,059 of Company-matching contributions to a defined contribution plan and $5,059 of profit-sharing contributions to a defined contribution plan.
Employment and Severance Agreements The Partnership has severance agreements with Mr. Gorman, Mr. Benavides, Mr. Mazoch and Ms. Pape that expire May 14, 2003. The severance agreements with Mr. Gorman, Mr. Benavides, Mr. Mazoch and Ms. Pape provide that in the event of a Changed Circumstance (as defined in the severance agreement) or a Changed Circumstance within one year of a Change in Control (as defined as a sale of substantially all of the Partnership's assets or a change in the ownership of fifty percent or more of the General Partner), the officer shall be entitled to: (i) a lump sum payment of one year of annual salary, (ii) immediate vesting of any unvested awards under the Restricted Unit Plan and (iii) payment of any incentive compensation payable to the executive in accordance with the Incentive Plan. 36 Restricted Unit Plan In January 1997, the General Partner adopted a restricted unit plan for key employees of the General Partner that provided for the award of rights to receive Common Units under certain restrictions including meeting thresholds tied to Available Cash and Adjusted Operating Surplus. In January 1998, the restricted unit plan was amended and restated, and the thresholds tied to Available Cash and Adjusted Operating Surplus were eliminated. The discussion that follows is based on the terms of the Amended and Restated Restricted Unit Plan (the "Restricted Unit Plan"). Initially, rights to receive 291,000 Common Units are available under the Restricted Unit Plan. From these Units, rights to receive 261,000 Common Units (the "Restricted Units") were allocated to approximately 34 individuals, subject to the vesting conditions described below and subject to other customary terms and conditions. One-third of the Restricted Units allocated to each individual vested annually beginning in December 1998. The remaining rights to receive 30,000 Common Units initially available under the Restricted Unit Plan may be allocated or issued in the future to key employees on such terms and conditions (including vesting conditions) as the Compensation Committee of the General Partner ("Compensation Committee") shall determine. Upon "vesting" in accordance with the terms and conditions of the Restricted Unit Plan, Common Units allocated to a plan participant will be issued to such participant. Units issued to participants may be newly issued Units acquired by the General Partner from the Partnership at then prevailing market prices or may be acquired by the General Partner in the open market. In either case, the associated expense will be borne by the Partnership. Until Common Units have vested and have been issued to a participant, such participant shall not be entitled to any distributions or allocations of income or loss and shall not have any voting or other rights in respect of such Common Units. No consideration will be payable by the plan participants upon vesting and issuance of the Common Units. The plan participant cannot sell the Common Units until one year after the date of vesting. Termination without cause in violation of a written employment agreement, or a Significant Event as defined in the Restricted Unit Plan, will result in immediate vesting of all non-vested units and conversion to Common Units without any restrictions. Bonus Plan In February 2001, 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 financial performance of the Partnership by rewarding 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 $1.5 million of Available Cash. The amount allocated to the bonus pool increases for each $1.5 million earned, such that a bonus pool of $1.2 million will exist if the Partnership earns $9.0 million of Available Cash. Bonuses will be paid to employees as each $1.5 million increment of Available Cash is earned, but only if distributions are made to the Common Unitholders. Payments under 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. In 2002, we paid no regular quarterly distributions to our Common Unitholders, so no bonuses accrued under the Bonus Plan. The Compensation Committee chose, however, to pay a bonus to all employees equivalent to one week of pay. Item 12. Security Ownership of Certain Beneficial Owners and Management We know of no one who beneficially owns in excess of five percent of the Common Units of the Partnership. As set forth below, certain beneficial owners own interests in the General Partner of the Partnership as of February 28, 2003. 37 Amount and Nature Name and Address of Beneficial Ownership Percent Title of Class of Beneficial Owner as of January 1, 2002 of Class ---------------------------------------- ------------------------- ----------------------------- ---------------- General Partner Interest Genesis Energy, Inc. 1 (1) 100.00 500 Dallas, Suite 2500 Houston, TX 77002 General Partner Interest Denbury Resources Inc. 1 (1) 100.00 5100 Tennyson Parkway. Plano, TX 75024 --------------------- (1) Denbury owns Genesis Energy, Inc. The reporting of the General Partner interest shall not be deemed to be a concession that such interest represents a security.
The following table sets forth certain information as of February 28, 2003, regarding the beneficial ownership of the Common Units by all directors of the General Partner, each of the named executive officers and all directors and executive officers as a group. This information is based on data furnished by the persons named. Amount and Nature of Beneficial Ownership --------------------------------------------------------------- Sole Voting and Shared Voting and Percent Title of Class Name Investment Power Investment Power of Class ------------------------- ------------------- -------------------- ------------------- ------------- Genesis Energy, L.P. Gareth Roberts - - * Common Unit Mark J. Gorman 25,525 - * Ronald T. Evans - 1,000 * Herbert I. Goodman 2,000 - * Susan O. Rheney - 700 * Phil Rykhoek 4,000 - * J. Conley Stone 1,000 - * Mark A. Worthey - - * Ross A. Benavides 9,283 - * Kerry W. Mazoch 8,085 584 * Karen N. Pape 3,386 - * All directors and executive officers as a group (11 in number) 53,279 2,284 * --------------------- * Less than 1%
The above table includes shares owned by certain members of the families of the directors or executive officers, including shares in which pecuniary interest may be disclaimed. Item 13. Certain Relationships and Related Transactions Through its control of the General Partner, Denbury has the ability to control the management of the Partnership and GCOLP. Genesis enters into transactions with Denbury and the General Partner in the ordinary course of its operations. During 2002, these transactions included: o Purchases of crude oil from Denbury totaling $26.4 million. o Provision of personnel to manage and operate the assets and operations of Genesis by the General Partner. Genesis reimbursed the General Partner for all direct and indirect costs of these services in the amount of $17.3 million. Item 14. Controls and Procedures We have evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report on Form 10-K (the "Evaluation Date"). Such 38 evaluation was conducted under the supervision and with the participation of our Chief Executive Officer (CEO) and Chief Financial Officer (CFO). Based on such evaluation, the CEO and CFO concluded that, as of the Evaluation Date, Genesis' disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to Genesis (including its consolidated subsidiaries) required to be included in Genesis' periodic filing under the Exchange Act. Since the Evaluation Date, there have not been any significant changes in our internal controls or in other factors that could significantly affect such controls. 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 43. (a)(3) Exhibits 3.1 Certificate of Limited Partnership of Genesis Energy, L.P. ("Genesis") (incorporated by reference to Exhibit 3.1 to Registration Statement, File No. 333-11545) 3.2 Third Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 4.1 of Form 8-K dated July 31, 2002) 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the "Operating Partnership") (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 1996) 3.4 Third Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 4.1 to Form 8-K dated July 31, 2002) 10.1 Purchase & Sale and Contribution & Conveyance Agreement dated as of December 3, 1996 among Basis Petroleum, Inc. ("Basis"), Howell Corporation ("Howell"), certain subsidiaries of Howell, Genesis, the Operating Partnership and Genesis Energy, L.L.C. (incorporated by reference to Exhibit 10.1 to Form 10-K for the year ended December 31, 1996) 10.2 First Amendment to Purchase & Sale and Contribution & Conveyance Agreement (incorporated by reference to Exhibit 10.2 to Form 10-K for the year ended December 31, 1996) 10.3 Severance Agreement between Genesis Energy, L.L.C. and Mark J. Gorman (incorporated by reference to Exhibit 10.5 of Form 10-K for the year ended December 31, 2001) 10.4 Severance Agreement between Genesis Energy, L.L.C. and Ross A. Benavides (incorporated by reference to Exhibit 10.6 of Form 10-K for the year ended December 31, 2001) 10.5 Severance Agreement between Genesis Energy, L.L.C. and Kerry W. Mazoch (incorporated by reference to Exhibit 10.7 of Form 10-K for the year ended December 31, 2001) 10.6 Severance Agreement between Genesis Energy, L.L.C. and Karen N. Pape (incorporated by reference to Exhibit 10.8 of Form 10-K for the year ended December 31, 2001) 10.7 Office Lease at One Allen Center between Trizec Allen Center Limited Partnership (Landlord) and Genesis Crude Oil, L.P. (Tenant) (incorporated by reference to Exhibit 10 to Form 10-Q for the quarterly period ended September 30, 1997) 10.8 Amended and Restated Restricted Unit Plan (incorporated by reference to Exhibit 10.18 to Form 10-K for the year ended December 31, 1997) 10.9 Amended and Restated Credit Agreement dated as of May 3, 2002, between Genesis Crude Oil, L.P., Genesis Energy, L.L.C., Genesis Energy, L.P., 39 Citicorp North America, Inc., and Certain Financial Institutions (incorporated by reference to Form 10-Q for the period ended March 31, 2002) * 10.10 Credit Agreement dated as of March 14, 2003, between Genesis Crude Oil, L.P., Genesis Energy, Inc. Genesis Energy, L.P., Fleet National Bank and Certain Financial Institutions 11.1 Statement Regarding Computation of Per Share Earnings (See Note 3 to the Consolidated Financial Statements - "Net Income Per Common Unit") * 21.1 Subsidiaries of the Registrant * 99.1 Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act 0f 2002. * 99.2 Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act 0f 2002 -------------------- * Filed herewith (b) Reports on Form 8-K None. 40 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 19 th day of March, 2003. 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. /s/ MARK J. GORMAN Director, Chief Executive Officer March 19, 2003 ------------------------- and President Mark J. Gorman (Principal Executive Officer) /s/ ROSS A. BENAVIDES Chief Financial Officer, March 19, 2003 ------------------------- General Counsel and Secretary Ross A. Benavides (Principal Financial Officer) /s/ KAREN N. PAPE Vice President and Controller March 19, 2003 ------------------------- Karen N. Pape (Principal Accounting Officer) /s/ GARETH ROBERTS Chairman of the Board and March 19, 2003 ------------------------- Director Gareth Roberts /s/ RONALD T. EVANS Director March 19, 2003 ------------------------- Ronald T. Evans /s/ HERBERT I GOODMAN Director March 19, 2003 ------------------------- Herbert I. Goodman /s/ SUSAN O. RHENEY Director March 19, 2003 ------------------------- Susan O. Rheney /s/ PHILIP RYKHOEK Director March 19, 2003 ------------------------- Philip Rykhoek /s/ J. CONLEY STONE Director March 19, 2003 ------------------------- J. Conley Stone /s/ MARK A. WORTHEY Director March 19, 2003 -------------------------- Mark A. Worthey 41 CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 CERTIFICATION I, Mark J. Gorman, certify that: 1. I have reviewed this annual report on Form 10-K of Genesis Energy, L.P.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 19, 2003 /s/ Mark J. Gorman ----------------------------------- Mark J. Gorman President & Chief Executive Officer 42 CERTIFICATION I, Ross A. Benavides, certify that: 1. I have reviewed this annual report on Form 10-K of Genesis Energy, L.P.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 19, 2003 /s/ Ross A. Benavides ---------------------------- Ross A. Benavides Chief Financial Officer 43 GENESIS ENERGY, L.P. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Independent Auditors' Report........................................... 44 Consolidated Balance Sheets, December 31, 2002 and 2001................ 46 Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000....................................... 47 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2002, 2001 and 2000................................. 48 Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000....................................... 49 Consolidated Statements of Partners' Capital for the Years Ended December 31, 2002, 2001 and 2000................................. 50 Notes to Consolidated Financial Statements............................. 51 44 INDEPENDENT AUDITORS' REPORT Genesis Energy, L.P. Houston, Texas We have audited the accompanying consolidated balance sheet of Genesis Energy, L.P., (the "Partnership") as of December 31, 2002, and the related consolidated statements of operations, comprehensive income, partners' capital and cash flows for the year then ended. 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 audit. The consolidated balance sheet of the Partnership as of December 31, 2001 and the consolidated statements of operations, partners' capital and cash flows for the two years in the period ended December 31, 2001, were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those statements dated March 8, 2002, and included an explanatory paragraph that described the Partnership's change in method of accounting for derivative instruments as discussed in Note 3 to those financial statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the December 31, 2002 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Partnership at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 8 to the consolidated financial statements, in 2002, the Partnership changed its method of accounting for goodwill. As discussed in Note 19 to the consolidated financial statements, in 2001, the Partnership changed its method of accounting for derivative instruments. As discussed above, the financial statements of Genesis Energy, L.P. as of December 31, 2001, and for the years ended December 31, 2001 and 2000, were audited by other auditors who have ceased operations. As described in Note 8, these financial statements have been revised to include transitional disclosures required by Statement of Financial Standards ("Statement") No. 142, Goodwill and Other Intangible Assets, which was adopted by the Partnership as of January 1, 2002. Our audit procedures with respect to the disclosures in Note 8 with respect to the year ended December 31, 2001, and the year ended December 31, 2000, included (a) agreeing the previously reported net income to the previously issued financial statements and the adjustments to reported net income representing amortization expense recognized in those periods related to goodwill as a result of initially applying Statement No. 142 to the Company's underlying records obtained from management, and (b) testing the mathematical accuracy of the reconciliation of adjusted net income to reported net income, and the related earnings-per-unit amounts. In our opinion, the disclosures for the year ended December 31, 2001, and the year ended December 31, 2000, in Note 8 are appropriate. However, we were not engaged to audit, review or apply any procedures to the 2001 or 2000 financial statements of the Partnership other than with respect to such disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 or 2000 financial statements taken as a whole. /s/ Deloitte & Touche LLP DELOITTE & TOUCHE LLP Houston, Texas March 14, 2003 45 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Genesis Energy, L.P.: We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P., (a Delaware limited partnership) as of December 31, 2001 and 2000, and the related consolidated statements of operations, cash flows and partners' capital for each of the three years in the period ended December 31, 2001. 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Genesis Energy, L.P. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 3 to the consolidated financial statements, effective January 1, 2001, the Partnership changed its method of accounting for derivative instruments. ARTHUR ANDERSEN LLP Houston, Texas March 8, 2002 This is a copy of the audit report previously issued by Arthur Andersen LLP in connection with our filing on Form 10-K for the year ended December 31, 2001. This audit report has not been reissued by Arthur Andersen LLP in connection with this filing on Form 10-K. 46 GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands) December 31, December 31, 2002 2001 -------- ---------- ASSETS CURRENT ASSETS Cash and cash equivalents...................................... $ 1,071 $ 5,777 Accounts receivable - Trade....................................................... 80,664 160,734 Related party............................................... - 1,064 Inventories.................................................... 4,952 3,737 Insurance receivable for pipeline spill costs.................. 3,425 1,570 Other.......................................................... 2,718 9,218 ---------- ---------- Total current assets........................................ 92,830 182,100 FIXED ASSETS, at cost............................................. 118,418 115,336 Less: Accumulated depreciation................................ (73,958) (69,626) ----------- ----------- Net fixed assets............................................ 44,460 45,710 OTHER ASSETS, net of amortization................................. 247 2,303 ---------- ---------- TOTAL ASSETS...................................................... $ 137,537 $ 230,113 ========== ========== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable - Trade....................................................... $ 82,640 $ 172,848 Related party............................................... 4,746 697 Accrued liabilities............................................ 8,834 10,144 ---------- ---------- Total current liabilities................................... 96,220 183,689 LONG-TERM DEBT.................................................... 5,500 13,900 COMMITMENTS AND CONTINGENCIES (Note 20) MINORITY INTERESTS................................................ 515 515 PARTNERS' CAPITAL Common unitholders, 8,625 units issued and outstanding......... 34,626 31,361 General partner................................................ 715 648 Accumulated other comprehensive loss........................... (39) - ---------- ---------- Total partners' capital..................................... 35,302 32,009 ---------- ---------- TOTAL LIABILITIES AND PARTNERS' CAPITAL........................... $ 137,537 $ 230,113 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. 47 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts) Year Ended December 31, ----------------------------------------------- 2002 2001 2000 ------------ ----------- ------------ REVENUES: Gathering and marketing revenues Unrelated parties................................. $ 888,559 $ 3,296,156 $ 4,274,519 Related parties................................... 3,036 29,847 35,095 Pipeline revenues.................................... 20,211 14,195 14,940 ------------ ----------- ------------ Total revenues................................. 911,806 3,340,198 4,324,554 COST OF SALES: Crude costs, unrelated parties....................... 832,860 3,257,137 4,150,888 Crude costs, related parties......................... 26,452 36,699 130,679 Field operating costs................................ 16,451 15,649 13,673 Pipeline operating costs............................. 12,928 10,897 8,652 ------------ ----------- ------------ Total cost of sales............................... 888,691 3,320,382 4,303,892 ------------ ----------- ------------ GROSS MARGIN............................................ 23,115 19,816 20,662 EXPENSES: General and administrative........................... 8,289 11,691 10,942 Depreciation and amortization........................ 5,813 7,546 8,032 Impairment of long-lived assets...................... - 45,061 - Other operating charges.............................. 1,500 1,500 1,387 ------------ ----------- ------------ OPERATING INCOME (LOSS)................................. 7,513 (45,982) 301 OTHER INCOME (EXPENSE): Interest income...................................... 69 166 259 Interest expense..................................... (1,104) (693) (1,269) Change in fair value of derivatives.................. (2,094) 2,259 - Net gain on disposal of surplus assets............... 708 167 1,148 ------------ ----------- ------------ Income (loss) before minority interests and cumulative effect of change in accounting principle.............. 5,092 (44,083) 439 Minority interests...................................... - (4) 258 ------------ ----------- ------------ Income (loss) before cumulative effect of change in accounting principle.................................. 5,092 (44,079) 181 Cumulative effect of change in accounting principle, net of minority interest effect........................... - 467 - ------------ ----------- ------------ NET INCOME (LOSS)....................................... $ 5,092 $ (43,612) $ 181 ============ =========== ============ NET INCOME PER COMMON UNIT- BASIC AND DILUTED: Income (loss) before cumulative effect of change in accounting principle............................ $ 0.58 $ (5.01) $ 0.02 Cumulative effect of change in accounting principle - 0.05 - Net income (loss)................................. $ 0.58 $ (4.96) $ 0.02 ============ ========== ============ WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING..... 8,625 8,624 8,617 ============ =========== ============
The accompanying notes are an integral part of these consolidated financial statements. 48 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In thousands) Year Ended December 31, --------------------------------------- 2002 2001 2000 ---------- --------- --------- NET INCOME (LOSS)................................................... $ 5,092 $ (43,612) $ 181 OTHER COMPREHENSIVE INCOME (LOSS): Change in fair value of derivatives used for hedging purposes.. (39) - - ---------- --------- --------- COMPREHENSIVE INCOME (LOSS)......................................... $ 5,053 $(43,612) $ 181 ========== ======== =========
The accompanying notes are an integral part of these consolidated financial statements. 49 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, --------------------------------------- 2002 2001 2000 ---------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)................................................. $ 5,092 $ (43,612) $ 181 Adjustments to reconcile net income to net cash provided by operating activities - Depreciation................................................... 4,965 6,228 6,714 Amortization of other assets................................... 848 1,318 1,318 Impairment of long-lived assets................................ - 45,061 - Cumulative effect of change in accounting principle............ - (467) - Change in fair value of derivatives............................ 2,055 (2,259) - Gain on disposal of surplus assets............................. (708) (167) (1,148) Minority interests equity in earnings (losses)................. - (4) 258 Restructuring costs............................................ - - 1,387 Other noncash charges.......................................... 1,500 1,605 1,801 Changes in components of working capital - Accounts receivable......................................... 81,134 167,666 (80,905) Inventories................................................. (1,051) (2,743) (590) Other current assets........................................ 4,645 3,565 4,436 Accounts payable............................................ (86,159) (154,117) 74,316 Accrued liabilities......................................... (4,904) (5,230) (3,355) ---------- --------- --------- Net cash provided by operating activities........................... 7,417 16,844 4,413 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment............................... (4,211) (1,882) (1,685) Change in other assets............................................ 5 - 11 Proceeds from sales of assets..................................... 2,243 453 1,942 ---------- --------- --------- Net cash (used in) provided by investing activities................. (1,963) (1,429) 268 CASH FLOWS FROM FINANCING ACTIVITIES: Bank borrowings (repayments), net................................. (8,400) (8,100) 2,100 Distributions to common unitholders............................... (1,725) (6,898) (19,645) Distributions to General Partner.................................. (35) (141) (352) Distributions to minority interest owner.......................... - (1) - Issuance of additional partnership interests...................... - - 13,702 Payment of restructuring costs.................................... - - (1,387) Purchase of treasury units, net................................... - (6) (255) ---------- --------- --------- Net cash used in financing activities............................... (10,160) (15,146) (5,837) Net (decrease) increase in cash and cash equivalents................ (4,706) 269 (1,156) Cash and cash equivalents at beginning of period.................... 5,777 5,508 6,664 ---------- --------- --------- Cash and cash equivalents at end of period.......................... $ 1,071 $ 5,777 $ 5,508 ========== ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 50 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (In thousands) Partners' Capital Accumulated Other Common General Treasury Comprehensive Unitholders Partner Units Income Total ----------- --------- -------- ------------- --------- Partners' capital, December 31, 1999................ $ 52,574 $ 1,051 $ (40) $ - $ 53,585 Net income.......................................... 177 4 - - 181 Cash distributions.................................. (19,645) (352) - - (19,997) Purchase of treasury units.......................... - - (255) - (255) Issuance of treasury units to Restricted Unit Plan participants...................................... - - 289 - 289 Excess of expense over cost of treasury units issued for Restricted Unit Plan.......................... 901 - - - 901 Elimination of additional partnership interests..... 17,248 352 - - 17,600 Elimination of subordinated limited partner interests in Operating Partnership.......................... 29,705 606 - - 30,311 ----------- --------- -------- ------------- --------- Partners' capital, December 31, 2000................ 80,960 1,661 (6) - 82,615 Net loss ........................................... (42,740) (872) - - (43,612) Cash distributions.................................. (6,898) (141) - - (7,039) Purchase of treasury units.......................... - - (6) - (6) Issuance of treasury units to Restricted Unit Plan participants...................................... - - 12 - 12 Excess of expense over cost of treasury units issued for Restricted Unit Plan.......................... 39 - - - 39 ----------- --------- -------- ------------- --------- Partners' capital, December 31, 2001................ 31,361 648 - - 32,009 Net income.......................................... 4,990 102 - - 5,092 Cash distributions.................................. (1,725) (35) - - (1,760) Change in fair value of derivatives used for hedging purposes - - - (39) (39) ----------- --------- -------- ------------- --------- Partners' capital, December 31, 2002................ $ 34,626 $ 715 $ - $ (39) $ 35,302 =========== ========= ======== ============= =========
The accompanying notes are an integral part of these consolidated financial statements. 51 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Partnership Structure Genesis Energy, L.P. ("GELP" or the "Partnership") was formed in December 1996 as 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") and owns a 2% general partner interest in GELP. The General Partner is owned by Denbury Gathering & Marketing, Inc. a subsidiary of Denbury Resources Inc. 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. Previous Structure Prior to a restructuring in December 2000, GELP owned 80.01% of GCOLP and Salomon Smith Barney Holdings Inc. ("Salomon") and Howell Corporation ("Howell") owned an aggregate of 2.2 million subordinated limited partner units in GCOLP ("Subordinated OLP Units"). As a result of the December 2000 restructuring, the Subordinated OLP Units were eliminated. 2. Basis of Presentation The accompanying financial statements and related notes present the consolidated financial position as of December 31, 2002 and 2001 for GELP and its results of operations, cash flows and changes in partners' capital for the years ended December 31, 2002, 2001 and 2000. 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. 3. Summary of Significant Accounting Policies Principles of Consolidation The Partnership owns and operates its assets through GCOLP, an operating limited partnership. The accompanying consolidated financial statements reflect the combined accounts of the Partnership and the operating partnership after elimination of intercompany transactions. Nature of Operations The principal business activities of the Partnership are the purchasing, gathering, transporting and marketing of crude oil in the United States. The Partnership gathers crude oil at the wellhead principally in the southern and southwestern states. The Partnership also owns and operates three crude oil pipelines. The pipelines are in Texas, Mississippi/Louisiana and Florida/Alabama. Use of Estimates The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management 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. Actual results could differ from those estimates. Cash and Cash Equivalents The Partnership considers investments purchased with an original maturity of three months or less to be cash equivalents. The Partnership has no requirement for compensating balances or restrictions on cash. 52 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 12 to 20 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. In 2001, the Partnership recorded an impairment charge related to its pipelines and related assets. See Note 11. The remaining book value of these assets will be amortized over the useful lives of the assets which, based on the estimated cash flows, is expected to be 7 to 15 years. 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. Other Assets Other assets consist primarily of intangibles. Intangibles include a covenant not to compete, which is being amortized over five years. Minority Interests Minority interests represent a 0.01% general partner interest in GCOLP held by the General Partner. Prior to the December 2000 restructuring, minority interests represented the Subordinated OLP Units held by Salomon and Howell totaling 19.59% and a 0.4% interest in GCOLP owned directly by the General Partner. Environmental Liabilities The Partnership provides 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. Revenue Recognition Gathering and marketing revenues are recognized when title to the crude oil is transferred to the customer. Pipeline revenues 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 losses 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. Cost of Sales 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. Derivatives Effective January 1, 2001, the Partnership accounts for its 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. Derivative instruments that hedge our commodity price risks involve our normal business activities, and have been designated as cash flow hedges under SFAS No. 133, SFAS No. 133 designates derivatives that hedge 53 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 net income per Common Unit is calculated on the weighted average number of outstanding Common Units. The weighted average number of Common Units outstanding was 8,625,000, 8,623,741 and 8,616,744 for the years ended December 31, 2002, 2001 and 2000, respectively. For this purpose, the 0.01% or 2% General Partner interest, as applicable, is excluded from net income. Diluted net income per Common Unit did not differ from basic net income per Common Unit for any period presented. 4. New Accounting Pronouncements 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 is effective for Genesis on January 1, 2003. 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 expiration of the lease term. For our pipelines, we expect that we will be 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 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 shall be applied in fiscal years beginning after May 15, 2002. The provisions related to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002. All other provisions shall be 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 the Partnership's results of operations. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3. Genesis will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. The impact that SFAS No. 146 54 will have on the consolidated financial statements will depend on the circumstances of any specific exit or disposal activity. In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others". 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 initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in this interpretation are effective for financial statements of interim or annual periods after December 15, 2002. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," which provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002, and financial reports containing condensed financial statements for interim periods beginning after December 15, 2002. At this time, there are no outstanding grants of Partnership units under our Restricted Unit Plan (see Note 15). Therefore, we do not believe that the adoption of this statement will have a material effect on either our financial position, results of operations, cash flows or disclosure requirements. 5. Business Segment and Customer Information Based on its management approach, the Partnership believes that all of its material operations revolve around the gathering, transportation and marketing of crude oil and it currently reports its operations, both internally and externally, as a single business segment. 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. Genesis received full payment for all sales to Enron Corporation subsidiaries. In 2000, no customer accounted for more than 10% of the Partnership's revenues. 6. Inventories Inventories consisted of the following (in thousands). December 31, 2002 2001 ------------ ------------ Crude oil inventories, at lower of cost or market...................... $ 4,841 $ 3,662 Fuel and supplies inventories, at lower of cost or market...................... 111 75 ------------ ------------ Total inventories.................... $ 4,952 $ 3,737 ============ ============ 7. Fixed Assets Fixed assets consisted of the following (in thousands). December 31, 2002 2001 ------------ ------------ Land and buildings....................... $ 3,492 $ 3,718 Pipelines and related assets............ 101,397 98,085 Vehicles and transportation equipment... 1,527 1,808 Office equipment, furniture and fixtures 3,138 2,809 Other .................................. 8,864 8,916 ------------ ------------ 118,418 115,336 Less - Accumulated depreciation.. (73,958) (69,626) ------------ ------------ Net fixed assets................. $ 44,460 $ 45,710 ============ ============ 55 Depreciation expense was $4,965,000, $6,228,000 and $6,714,000 and for the years ended December 31, 2002, 2001 and 2000, respectively. In 2001, the Partnership recorded an impairment charge related to its pipeline assets of $38,049,000. See Note 11. 8. Other Assets Other assets consisted of the following (in thousands). December 31, 2002 2001 ------------ ------------ Covenant not to compete................... $ 4,238 $ 4,238 NYMEX seats............................... - 1,203 Other..................................... 42 47 ------------ ------------ 4,280 5,488 Less - Accumulated amortization.... (4,033) (3,185) ------------- ------------ Net other assets............ $ 247 $ 2,303 ============ ============ 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, 2002, no impairment has occurred. Amortization expense for goodwill was $470,000 for the years ended December 31, 2001 and 2000. Amortization expense for the covenant-not-to-compete was $848,000 for the each of the years ended December 31, 2002, 2001 and 2000. Accumulated amortization of the covenant-not-to-compete was $4,033,000 and $3,185,000 at December 31, 2002 and 2001, respectively. The estimated aggregate amortization expense for 2003 is expected to be $205,000, at which time the covenant-not-to-compete will have expired. Had SFAS No. 142 been in effect prior to January 1, 2002, reported net income and net income per unit would have been as follows (in thousands, except per unit amounts): Year Ended December 31, 2002 2001 2000 ----------- ----------- ----------- Reported net income............... $ 5,092 $ (43,612) $ 181 Goodwill amortization, after minority interest effect........ $ - $ 470 $ 384 ----------- ----------- ----------- Adjusted net income............... $ 5,092 $ (43,142) $ 565 =========== =========== =========== Net income per unit-basic and diluted: Reported net income............... $ 0.58 $ (4.96) $ 0.02 Goodwill amortization............. - $ 0.05 $ 0.04 ----------- ----------- ----------- Adjusted net income............... $ 0.58 $ (4.91) $ 0.06 =========== =========== =========== In February 2002, the Partnership sold its NYMEX seats for a total of $1,700,000. 9. Credit Resources In 2001, Genesis had a $300 million Master Credit Support Agreement ("Guaranty Facility") with Salomon and a $25 million working capital facility ("WC Facility") with BNP Paribas. Effective December 19, 2001, GCOLP entered into a two-year $130 million Senior Secured Revolving Credit Facility ("Credit Agreement") with Citicorp North America, Inc. ("Citicorp"). Citicorp and Salomon, the former owner of the partnership's General Partner, are both wholly-owned subsidiaries of Citigroup Inc. The Credit Agreement replaced the Guaranty Facility and the WC Facility. In May 2002, the Partnership elected, under the terms of the Credit Agreement, to amend the Credit Agreement to reduce the maximum facility amount to $80 million. The Credit Agreement had a $25 million sublimit for 56 working capital loans. Any amount not being used for working capital loans was available for letters of credit to support crude oil purchases. During the first four months of 2002, Salomon provided guaranties to the Partnership's counterparties under a transition arrangement between Salomon, Citicorp and the Partnership. For crude oil purchases in December 2001 and April 2002, a maximum of $100 million in guaranties were available to be issued under the Salomon guaranty facility. Beginning with May 2002, Citicorp provided letters of credit to the Partnership's counterparties. In March 2003, the Partnership replaced the Citicorp Credit Agreement with a $65 million three-year credit facility with a group of banks with Fleet National Bank as agent ("Fleet Agreement"). The Fleet Agreement 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 Agreement are as follows: o Letter of credit fees are based on the Applicable Usage Level ("AUL") and will range from 2.00% to 3.00%. During the first six months of the facility, the rate will be 2.50%. The AUL is a function of the facility usage to the borrowing base on that day. o The interest rate on working capital borrowings is also based on the AUL and allows for loans 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%. During the first six months of the facility, the rate will be the Libor rate plus 2.50%. o The Partnership will pay a commitment fee on the unused portion of the $65 million commitment. This commitment fee is also based on the AUL and will range from 0.375% to 0.50%. During the first six months of the facility, the commitment fee will be 0.50%. o The amount that the Partnership may have outstanding cumulatively in working capital borrowings and letters of credit is subject to a Borrowing Base calculation. The Borrowing Base (as defined in the Fleet Credit Agreement) generally includes cash balances, net accounts receivable and inventory, less deductions for certain accounts payable, and is calculated monthly. o Collateral under the Fleet Agreement consists of the Partnership's accounts receivable, inventory, cash accounts, margin accounts and property and equipment. o The Fleet Agreement contains covenants requiring a Current Ratio (as defined in the Fleet Agreement), a Leverage Ratio (as defined in the Fleet Agreement), a Cash Flow Coverage Ratio (as defined in the Fleet Agreement), a Funded Indebtedness to Capitalization Ratio (as defined in the Fleet Agreement), Minimum EBITDA, and limitations on distributions to Unitholders. Under the Citicorp Credit Agreement, distributions to Unitholders and the General Partner could only be made if the Borrowing Base exceeds the usage (working capital borrowings plus outstanding letters of credit) under the Citicorp Credit Agreement for every day of the quarter by at least $20 million. Under the Fleet Agreement, this provision is changed to require that the Borrowing Base exceed the usage under the Fleet Credit Facility by at least $10 million plus the distribution measured once each month. See additional discussion below under "Distributions". At December 31, 2002, the Partnership had $5.5 million outstanding under the Citicorp Credit Agreement. Due to the revolving nature of loans under the Citicorp Credit Agreement, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of December 31, 2003. As a result of the refinancing of the debt under the Fleet Agreement, this outstanding balance is shown as long-term debt in the consolidated balance sheet. At December 31, 2002, the Partnership had letters of credit outstanding under the Citicorp Credit Agreement totaling $26.3 million, comprised of $13.8 million and $12.5 million for crude oil purchases related to December 2002 and January 2003, respectively. Credit Availability As a result of the Partnership's decision to reduce the level of bulk and exchange transactions, credit support in the form of letters of credit has been less in 2002 than it was in 2001. However, any significant decrease in the Partnership's financial strength, regardless of the reason for such decrease, may increase the number of transactions 57 requiring letters of credit, which could restrict its gathering and marketing activities due to the limitations of the Fleet Agreement and Borrowing Base. This situation could in turn adversely affect its ability to maintain or increase the level of its purchasing and marketing activities or otherwise adversely affect its profitability and Available Cash. Distributions Generally, GCOLP will distribute 100% of its 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 the cash receipts less cash disbursements of GCOLP adjusted for net changes to reserves. As a result of the restructuring approved by Unitholders in December 2000, the target minimum quarterly distribution ("MQD") for each quarter was reduced to $0.20 per unit. The Partnership has not made a regular quarterly distribution since the fourth quarter of 2001. Under the Citicorp Agreement, distributions to Unitholders and the General Partner could only be made if the Borrowing Base exceeded the usage (working capital borrowings plus outstanding letters of credit) under the Citicorp Agreement for every day of the quarter by at least $20 million plus the distribution. Under the Fleet Agreement, this provision is changed to require that the Borrowing Base exceed the usage under the Fleet Agreement by at least $10 million plus the distribution measured once each month. For the first and second quarters of 2002, the Partnership did not pay a distribution as the excess of the Borrowing Base over the usage dropped below the required level. During the third quarter of 2002, the Partnership met the test and thus was not restricted from making a distribution under the Credit Agreement. However, a distribution was not made for the third quarter of 2002 because of a reserve established fro future needs of the Partnership. These reserves exceeded Available Cash for the third quarter of 2002. Similarly, the Partnership did not make a distribution for the fourth quarter of 2002 as reserves again exceeded Available Cash. Such future needs of the Partnership include, but are not limited to, the fines that are being imposed in connection with the crude oil spill that occurred on the Mississippi System in December 1999 and future expenditures that will be required for pipeline integrity management programs required by federal regulations. Management of the Partnership is still evaluating plans to restore the distribution. Any distribution to restore the distribution will take into account the Partnership's ability to sustain the distribution on an ongoing basis with cash generated by the existing asset base, capital requirements needed to maintain and optimize the performance of the asset base, and the Partnership's ability to finance its existing capital requirements and accretive acquisitions. If distributions are resumed, the distribution per common unit may be for less than the MQD target of $0.20 per unit. 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. 10. Partnership Equity Partnership equity in GELP consists 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. The general partner interest is held by the 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, 2002. 11. 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. 58 12. 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 including 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. In connection with the restructuring of the Partnership in December 2000, costs totaling $1.4 million were incurred primarily for legal and accounting fees, financial advisor fees, proxy solicitation expenses and the costs to print and mail proxy materials to Common Unitholders. These costs are reflected as other operating charges in the consolidated statement of operations for 2000. The cash needed to fund these expenses was provided from the final distribution support obligation payment made by Salomon pursuant to the terms of the proxy statement. 13. Transactions with Related Parties Sales, purchases and other transactions with affiliated companies, except the guarantee fees paid to Salomon, in the opinion of management, are conducted under terms no more or less favorable than those conducted with unaffiliated parties. Sales and Purchases of Crude Oil A summary of sales to and purchases from related parties of crude oil is as follows (in thousands). Year Ended December 31, 2002 2001 2000 ----------- ----------- ----------- Purchases from Denbury............... $ 26,452 Sales to Salomon affiliates.......... $ 3,036 $ 29,847 $ 35,095 Purchases from Salomon and Howell affiliates......................... $ - $ 36,699 $ 130,679 Denbury became a related party in May 2002. Purchases during the period from May 14, 2002 to December 31, 2002 from Denbury were $26.5 million. Purchases in 2002 from Denbury before it became an affiliate were $10.9 million. Purchases from Denbury are secured by letters of credit. The related party sales in all years were made to Phibro, Inc., ("Phibro"), a subsidiary of Salomon. Purchases of $36.7 million and $121.1 million, respectively, were made in 2001 and 2000 from Phibro. These transactions were bulk and exchange transactions. Purchases of wellhead production were made from Howell in 2000 of $9.6 million. General and Administrative Services The Partnership does not directly employ any persons to manage or operate its business. Those functions are provided by the General Partner. The Partnership reimburses the General Partner for all direct and indirect costs of these services. Total costs reimbursed to the General Partner by the Partnership were $17,280,000, $18,089,000, and $16,946,000 for the years ended December 31, 2002, 2001 and 2000, respectively. Credit Agreement In December 2001, Citicorp began providing the Partnership with a working capital and letter of credit facility. In January 1, 2002, until Mary 14, 2002, when Citicorp ceased to be a related party, the Partnership incurred letter of credit fees, interest and commitment fees totaling $396,000 under the Credit Agreement. In 2001, the Partnership paid Citicorp for interest and commitment fees totaling $27,000 and $900,000 as a fee for providing the facility. This facility fee is being amortized to earnings over the two-year life of the Credit Agreement and is included in interest expense on the consolidated statements of operations. Guaranty Fees In 2001 and 2000, 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, 2001 and 2000, the Partnership paid Salomon $61,000, $1,250,000 and $1,712,000, 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. 59 14. Supplemental Cash Flow Information In 2000, two noncash transactions occurred as a result of the restructuring of the Partnership. Additional Partnership Interests and minority interests related to the Subordinated OLP Units were eliminated and resulted in an increase in the capital accounts of the Common Unitholders and General Partner of GELP. Cash received by the Partnership for interest during the years ended December 31, 2002, 2001 and 2000 was $68,000, $195,000, and $241,000, respectively. Cash payments for interest were $537,000, $1,391,000, and $1,370,000 during the years ended December 31, 2002, 2001 and 2000, respectively. 15. Employee Benefit Plans The Partnership does not directly employ any of the persons responsible for managing or operating the Partnership. 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 the lesser of 50% of each employee's annual pretax contribution or 3% of each employee's total compensation. 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 $564,000, $603,000, and $570,000 for the years ended December 31, 2002, 2001 and 2000, respectively. The General Partner also provided certain health care and survivor benefits for its active employees. In 2002, 2001 and 2000, these benefit programs were self-insured. 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 $1,360,000, $1,526,000, and $1,718,000 in 2002, 2001 and 2000, respectively. Restricted Unit Plan In January 1997, the General Partner adopted a restricted unit plan for key employees of the General Partner that provided for the award of rights to receive Common Units under certain restrictions, including meeting thresholds tied to Available Cash and Adjusted Operating Surplus. In January 1998, the restricted unit plan was amended and restated, and the thresholds tied to Available Cash and Adjusted Operating Surplus were eliminated. The discussion that follows is based on the terms of the Amended and Restated Restricted Unit Plan (the "Restricted Unit Plan"). Initially, rights to receive 291,000 Common Units are available under the Restricted Unit Plan. From these Units, rights to receive 261,000 Common Units (the "Restricted Units") were allocated to approximately 34 individuals, subject to the vesting conditions described below and subject to other customary terms and conditions. One-third of the Restricted Units allocated to each individual vested annually beginning in December 1998. The remaining rights to receive 30,000 Common Units available under the Restricted Unit Plan may be allocated or issued in the future to key employees on such terms and conditions (including vesting conditions) as the Compensation Committee of the General Partner ("Compensation Committee") shall determine. Upon "vesting" in accordance with the terms and conditions of the Restricted Unit Plan, Common Units allocated to a plan participant will be issued to such participant. Units issued to participants may be newly issued Units acquired by the General Partner from the Partnership at then prevailing market prices or may be acquired by the General Partner in the open market. In either case, the associated expense will be borne by the Partnership. Until Common Units have vested and have been issued to a participant, such participant shall not be entitled to any distributions or allocations of income or loss and shall not have any voting or other rights in respect of such Common Units. No consideration will be payable by the participants in the Restricted Unit Plan upon vesting and issuance of the Common Units. Additionally, the participant cannot sell the Common Units until one year after the date of vesting. Termination without cause in violation of a written employment agreement, or a Significant Event as defined in the Restricted Unit Plan, will result in immediate vesting of all non-vested units and conversion to Common Units without any restrictions. 60 In 2001 and 2000, the Partnership recorded expense of $55,000 and $1,192,000, respectively, related to the Restricted Units. Bonus Plan In February 2001, 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 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 $1.5 million of Available Cash. The amount allocated to the bonus pool increases for each $1.5 million earned, such that a bonus pool of $1.2 million will exist if the Partnership earns $9.0 million of Available Cash. Bonuses will be paid to employees as each $1.5 million increment of Available Cash is earned, but only if distributions are made to the Common Unitholders. Payments under the Bonus Plan will be at the discretion of the Compensation Committee, and the General Partner will be able to amend or change the Bonus Plan at any time. 16. Sale of Tractor/Trailer Fleet Management of the Partnership made the decision to sell its existing tractor/trailer fleet and replace it with vehicles provided by Ryder Transportation Services ("Ryder") under an operating lease. During 2000, the Partnership sold 22 tractors and 68 trailers for a total of $1,802,000 and recognized a gain of $1,037,000 on the sale of this equipment. The remaining 31 tractors were sold on January 8, 2001, for $400,000. The net book value of those tractors, totaling $286,000, was reflected in other current assets at December 31, 2000. A gain of $114,000 on this sale was recorded in 2001. 17. Concentration and Credit Risk The Partnership derives its revenues from customers primarily in the crude oil industry. This industry concentration has the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes that the credit risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily 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. The Partnership has established various procedures to manage its 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 management's established credit criteria are met. 18. 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. At December 31, 2002 and 2001, the Partnership had no option contracts outstanding. At December 31, 2000, the carrying amount and estimated fair values of option contracts used as hedges was $7.3 million. Quoted market prices were used in determining the fair value of the option contracts. If quoted prices were not available, fair values were estimated on the basis of pricing models or quoted prices for contracts with similar characteristics. Judgment is required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. 19. Derivatives The Partnership's 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 its exposure to such market fluctuations, the Partnership enters into various financial contracts, including futures, options and swaps. Normally, any contracts used to hedge market risk are less than one year in duration. 61 The Partnership utilizes crude oil futures contracts and other financial derivatives to reduce its exposure to unfavorable changes in crude oil prices. On January 1, 2001, the Partnership 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. SFAS No. 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value 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 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. Under SFAS No. 133, the Partnership marks to fair value its 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 the Partnership's 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. The Partnership regularly reviews its contracts to determine if the contracts qualify for treatment as derivatives in accordance with SFAS No. 133. At December 31, 2002, the Partnership 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) will occur in January 2003, and all related amounts currently held in other comprehensive income will be reclassed to the income statement in 2003. The Partnership determined that its other derivative contracts qualified for the normal purchase and sale exemption at December 31, 2002. Therefore, the decrease in fair value of the Partnership's net asset for derivatives not qualifying as hedges decreased to zero. This decrease in fair value of $2.1 million is recorded as a loss in the consolidated statements of operations under the caption "Change in fair value of derivatives". The consolidated balance sheet at December 31, 2001, included $5.5 million in other current assets and $3.5 million in accrued liabilities as a result of recording the fair value of derivatives. In 2001, the Partnership did not designate any of its derivatives as hedging instruments under SFAS No. 133. 20. Commitments and Contingencies Commitments and Guarantees The Partnership leases office space for its headquarters office under a long-term lease. The lease extends until October 31, 2005. Ryder provides tractors and trailers to the Partnership under an operating lease that also includes full-service maintenance. Under the terms of the lease, the Partnership leases 75 tractors and 75 trailers. The Partnership pays a fixed monthly rental charge for each tractor and trailer and a fee based on mileage for the maintenance services. The Partnership leases three tanks for use in its pipeline operations. The tank leases expire in 2004. Additionally, it leases a segment of pipeline. Under the terms of that lease, the Partnership makes lease payments based on throughput, and has no minimum volumetric or financial requirements remaining. The Partnership also leases service vehicles for its field personnel. The future minimum rental payments under all noncancelable operating leases as of December 31, 2002, were as follows (in thousands). 62 Office Tractors and Service Space Trailers Tanks Vehicles Total -------- --------- --------- --------- --------- 2003...... $ 431 $ 2,832 $ 465 $ 374 $ 4,102 2004...... 489 2,838 465 373 4,165 2005...... 410 2,387 - 222 3,019 2006...... 18 997 - - 1,015 2007....... 15 887 - - 902 2008 and thereafter. - 2,518 - - 2,518 --------- --------- --------- --------- --------- Total minimum lease obligations $ 1,363 $ 12,459 $ 930 $ 969 $ 15,721 ========= ========= ========= ========= ======== Total operating lease expense was as follows (in thousands). Year ended December 31, 2002.............................. $ 4,713 Year ended December 31, 2001.............................. $ 4,379 Year ended December 31, 2000.............................. $ 2,500 The Partnership has guaranteed $5.2 million of residual value related to the leases of tractors and trailers. Management of the Partnership believes the likelihood the Partnership 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 $9.9 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 Citicorp under the terms of the Citicorp Agreement related to borrowings and letters of credit. Borrowings at December 31, 2002 were $5.5 million and are reflected in the consolidated balance sheet. To the extent liabilities exist under the letters of credit, such liabilities are include in the consolidated balance sheet. The Partnership has contractual commitments (forward contracts) arising in the ordinary course of its crude oil marketing activities. At December 31, 2002, the Partnership had commitments to purchase 2,743,000 barrels of crude oil in January 2003, and 1,864,000 barrels of crude oil between February 2003, and June 2004. The partnership had commitments to sell 2,810,000 barrels of crude oil in January 2003, and 749,000 barrels of crude oil between February 2003 and July 2003. All of these contracts are associated with market-price-related contracts. The total commitment to purchase crude oil would be valued at $139.9 million, using market prices at December 31, 2002. The total commitment to sell crude oil would be valued at $110.2 million, using market prices at December 31, 2002. In general, the Partnership expects to increase its expenditures in the future to comply with higher industry and regulatory safety standards. While the total amount of increased expenditures cannot be accurately estimated at this time, the Partnership anticipates that it will expend a total of approximately $9.6 million in 2003 and 2004 for testing and rehabilitation under regulations requiring assessment of the integrity of crude oil pipelines. Unitholder Litigation On June 7, 2000, Bruce E. Zoren, a holder of units of limited partner interests in the partnership, filed a putative class action complaint in the Delaware Court of Chancery, No. 18096-NC, seeking to enjoin the restructuring and seeking damages. Defendants named in the complaint include the Partnership, Genesis Energy L.L.C., members of the board of directors of Genesis Energy, L.L.C., and Salomon Smith Barney Holdings Inc. The plaintiff alleges numerous breaches of fiduciary duty loyalty owed by the defendants to the purported class in connection with making a proposal for restructuring. In November 2000, the plaintiff amended its complaint. In response, the defendants removed the amended complaint to federal court. On March 27, 2002, the federal court dismissed the suit; however, the plaintiff filed a motion to alter or amend the judgment. On May 15, 2002, the federal court denied the motion to alter or amend. The time for an appeal to be taken expired without an appeal being filed. On June 11, 2002, the plaintiff refiled the original complaint in the Delaware Court of Chancery, No. 19694-NC. On July 19, 2002, the defendants moved to dismiss the complaint for failure to state a claim upon which relief can be granted. The court has not ruled on that motion. Management of the General Partner believes that the 63 complaint is without merit and intends to vigorously defend the action. Management of the Partnership believes that any potential liability will be covered by insurance. Pennzoil Litigation The Partnership was 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") seeks 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 claims the fire and explosion was caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. We believe that the suit is without merit and intend to vigorously defend ourselves in this matter. We believe that any potential liability will be covered by insurance. 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. We believe that any potential liability will substantially be covered by insurance. Other Matters On December 20, 1999, the Partnership had a spill of crude oil from its 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 financial impact to the Partnership for the cost of the clean-up has not been material. As a result of this crude oil spill, certain federal and state regulatory agencies will likely impose fines and penalties that would not be covered by insurance. The Partnership is subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance. The Partnership's management has made an assessment of its potential environmental exposure, and as a result of the spill from the Mississippi System, a total accrual of $3.0 million was recorded during 2002 and 2001. The Partnership is 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 the financial position, results of operations or cash flows of the Partnership.