=============================================================================== 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, 2001 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 ------- 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 March 1, 2002, was approximately $27 million. At March 1, 2002, 8,625,000 Common Units were outstanding. ===============================================================================
2 GENESIS ENERGY, L.P. 2001 FORM 10-K ANNUAL REPORT Table of Contents Page ---- Part I Item 1. Business 3 Item 2. Properties 9 Item 3. Legal Proceedings 10 Item 4. Submission of Matters to a Vote of Security Holders 10 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 23 Item 8. Financial Statements and Supplementary Data 23 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 24 Part III Item 10. Directors and Executive Officers of the Registrant 24 Item 11. Executive Compensation 25 Item 12. Security Ownership of Certain Beneficial Owners and Management 28 Item 13. Certain Relationships and Related Transactions 29 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 29
3 PART I Item 1. Business General Genesis Energy, L.P., a Delaware limited partnership, was formed in December 1996. Genesis Energy, L.P. conducts its operations through its affiliated limited partnership, Genesis Crude Oil, L.P. and its subsidiary partnerships (collectively, the "Partnership" or "Genesis"). The Partnership is an independent gatherer and marketer of crude oil. Genesis' operations are concentrated in Texas, Louisiana, Alabama, Florida, Mississippi and New Mexico. In its gathering and marketing business, Genesis is 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"). Until December 31, 2001, the Partnership also made bulk purchase of crude oil at pipeline and terminal facilities. The Partnership's 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 refineries or other customers at favorable prices. In addition to its gathering and marketing business, Genesis' operations include transportation of crude oil at regulated published tariffs on its three common carrier pipeline systems. Genesis utilizes its trucking fleet of approximately 75 leased tractor- trailers and its gathering lines to transport crude oil purchased at the wellhead to pipeline injection points, terminals and refineries for sale to its customers. It also transports purchased crude oil on trucks, barges and pipelines owned and operated by third parties. Prior to the first quarter of 2002, Genesis made purchases of crude oil in bulk at pipeline and terminal facilities for resale to refineries or other customers. When opportunities arise to increase margin or to acquire a grade of crude oil that more nearly matches the specifications for crude oil the Partnership is obligated to deliver, Genesis may exchange crude oil with third parties through exchange or buy/sell agreements. In the fourth quarter of 2001, Genesis purchased an average of approximately 80,000 barrels per day of crude oil at the wellhead. Genesis currently transports a total of approximately 80,000 barrels per day on its three common carrier crude oil pipeline systems and related gathering lines. 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. Genesis Energy, L.L.C. (the "General Partner"), a Delaware limited liability company, serves as the sole general partner of Genesis Energy, L.P., and as the operating general partner of its affiliated limited partnership, 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 Salomon Smith Barney Holdings Inc. ("Salomon") (54%) and Salomon Brothers Holding Company Inc. (46%). Business Overview In its gathering and marketing business, the Partnership seeks to purchase and sell crude oil at points along the Distribution Chain where gross margins can be achieved. Genesis generally purchases crude oil at prevailing prices from producers at the wellhead under short-term contracts and then transports the crude oil along the Distribution Chain for sale to or exchange with customers. Prior to the first quarter of 2002, Genesis also purchased crude oil in bulk at major pipeline terminal points. The Partnership's margins from its 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. Genesis generally enters 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, Genesis often exchanges 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 Genesis purchases crude oil, it simultaneously establishes a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into
4 a future delivery obligation with respect to futures contracts on the New York Mercantile Exchange ("NYMEX"). Through these transactions, the Partnership seeks 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 the Partnership's policy not to acquire and hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes. Through the pipeline systems it owns and operates, the Partnership transports crude oil for itself and others pursuant to tariff rates regulated by the Federal Energy Regulatory Commission ("FERC") or the Texas Railroad Commission. Accordingly, the Partnership offers 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. The margins from the Partnership's pipeline operations are generated by the difference between the regulated published tariff and the fixed and variable costs of operating and maintaining the pipeline. Producer Services Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. Through its team of crude oil purchasing representatives, Genesis maintains ongoing relationships with more than 800 producers. The Partnership believes that its ability to offer high-quality field and administrative services to producers is a key factor in its 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, the Partnership must maintain records of title and division order interests in an accurate and timely manner for purposes of making 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 2001, Genesis distributed payments to approximately 24,000 interest owners. Credit Genesis' credit standing is a major consideration for parties with whom Genesis does business. At times, in connection with its crude oil purchases or exchanges, Genesis is 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. In November and December 2001, Genesis experienced an increase in the requests it received to furnish guarantees or letters of credit as a result of the bankruptcy of Enron Corporation ("Enron") and the Partnership's announcement that it had exposure of $21 million to an Enron subsidiary. The Partnership received payment in full for its receivable from the Enron subsidiary. However, the impact of the Enron bankruptcy on credit requirements in the crude oil gathering industry has continued to affect requests from Genesis' counterparties for credit support. Historically, Salomon provided guarantees at the Partnership's request in connection with the purchase of crude oil under a Master Credit Support Agreement ("Guaranty Facility"). On December 19, 2001, the Partnership entered into a Credit Agreement with Citicorp North America, Inc. ("Citicorp") through which Citicorp will begin supplying letters of credit to counterparties at Genesis' request, after a transition period lasting for the first four months of 2002. See Note 8 of Notes to Consolidated Financial Statements for further description of the Citicorp Credit Agreement. When Genesis markets crude oil, it 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 Genesis' business. Management believes that Genesis' sales are made to creditworthy entities or entities with adequate credit support. Under the terms of the Guaranty Facility and Credit Agreement, Citicorp has significant authority to influence and restrict Genesis'
5 extension of credit to customers. Genesis has not experienced any nonpayments or nonperformance by its customers during 2001 or 2002. Credit review and analysis are also integral to Genesis' 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, Genesis must determine whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend Genesis in the event any third party should bring a protest, action or complaint in connection with the ultimate distribution of production proceeds by the operator. Competition In the various business activities described above, the Partnership is 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 the Partnership's pipeline systems and trucking facilities give the Partnership access to domestic crude oil production throughout its area of operations. The Partnership purchases leasehold barrels from more than 800 producers. In 2001, approximately 26% of the leasehold barrels were purchased from ten producers. The Partnership has considerable flexibility in marketing the volumes of crude oil that it purchases, without dependence on any single customer or transportation or storage facility. The Partnership's largest competitors in the purchase of leasehold crude oil production are EOTT Energy Partners, L.P., Equiva Trading Company, GulfMark Energy, Inc., Plains All American Pipeline, L.P. and TEPPCO Partners, L.P. Additionally, Genesis competes with many regional or 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. Genesis' most significant competitors in its 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. The Partnership believes 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 Genesis' pipelines will be built in the same geographic areas in the near future, provided that Genesis' pipelines continue to have available capacity to satisfy demands of shippers and that its tariffs remain at competitive levels. Employees To carry out various purchasing, gathering, transporting and marketing activities, the General Partner employed, at February 28, 2002, approximately 250 employees, including management, truck drivers and other operating personnel, division order analysts, accountants, tax specialists, contract administrators, traders, schedulers, marketing and credit specialists and employees involved in Genesis' pipeline operations. None of the employees are represented by labor unions, and the General Partner believes that its relationships with the employees are good. Environmental Matters Genesis is 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. Risk of accidental leaks and spills are associated with the transportation of crude oil. Although compliance with such laws has not had a significant effect on Genesis' business, such compliance in the future could prove to be costly, and there can be no assurance that Genesis will not incur such costs in material amounts.
6 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. Management believes that Genesis is 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. Management believes that Genesis is in substantial compliance with the Clean Water Act and OPA. 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 Genesis's operations, substances may be generated or handled which fall within the definition of "hazardous substances." Although Genesis has applied operating and disposal practices that were standard 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 Genesis or under locations where such wastes have been taken for disposal. Further Genesis may own or operate properties that in the past were operated by third parties whose operations were not under Genesis' 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 Genesis 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. Genesis is 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, Genesis 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 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 Genesis 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's management has made an assessment of its potential environmental exposure and, primarily as a result of the spill from the Mississippi System, has recorded a charge of $1.5 million in 2001. Regulation Pipeline regulation Interstate Regulation Generally. 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"). The ICA requires that petroleum pipeline rates be just and reasonable and not unduly discriminatory. The ICA permits
7 challenges to proposed new or changed rates by protest and to rates that are already final and in effect by complaint, and provides that upon an appropriate showing a complainant may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint. None of Genesis's tariffs have been subjected to a protest or complaint by any shipper or other interested party. In general, the ICA requires that petroleum pipeline rates be cost based and permits them to generate operating revenues on the basis of projected volumes sufficient to cover, among other things: (i) operating expenses, (ii) depreciation and amortization, (iii) federal and state income taxes determined on a separate company basis and adjusted or "normalized" to reflect the impact of timing differences between book and tax accounting for certain expenses, primarily depreciation and (iv) an overall allowed rate of return on the pipeline's "rate base." Generally, rate base is a measure of investment in or value of the common carrier assets which are used and useful in providing the regulated services. 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. Under the new regulations, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods, minus one percent. 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. FERC's regulations provide, and a recent FERC order in a contested pipeline rate proceeding affirms, that shippers may not challenge that portion of the pipeline's rates which was grandfathered whenever the pipeline files for its annual indexed rate increase; such challenges are limited to the amount of the increase only unless, in a separate showing, the complainant satisfies the threshold requirement to show that a "substantial change" has occurred in the economic circumstances or the nature of the pipeline's services. Rate decreases are mandated under the new regulations if the index decreases and the carrier has been collecting rates equal to the rate ceiling. The new indexing methodology can be applied to any existing rate, including in particular all "grandfathered" rates, but also applies to rates under investigation. If such rate is subsequently adjusted, the ceiling level established under the index must be likewise adjusted. The new indexation methodology is expected to cover all normal cost increases. Cost-of-service ratemaking, while still available to the pipeline for certain rate increases and to establish initial rates for new service, is generally disfavored except in specified circumstances, primarily a substantial divergence between the actual cost experienced by the carrier and the rate resulting from the index such that the rate at the ceiling level would preclude the carrier from being able to charge a just and reasonable rate. FERC regulations also allow rate changes to occur through market-based rates (for pipeline services which have been found to be eligible for such rates) and through settlement rates, which are rates unanimously agreed to by the carrier and all shippers as appropriate. In respect of new facilities and new services requiring the establishment of new, initial rates, the carrier may rely on either cost-of-service ratemaking or may initiate service under rates which have been contractually agreed with at least one nonaffiliated shipper; however, other shippers may protest any new rates established in this manner, in which event a cost-of-service showing is required. The General Partner adopted preexisting tariffs and rates pertaining to the Jay and Mississippi Systems and has relied on the indexation procedures available under FERC regulations. Nevertheless, by protest, complaint or shipper challenge to Genesis's grandfathered or indexed rates, Genesis could become involved in a cost-of-service proceeding before FERC and be required to defend and support its rates based on costs. In any such cost-of-service rate proceeding involving rates of the FERC-regulated Jay and Mississippi Systems, FERC would be permitted to inquire into and determine all relevant matters including such issues as (i) the appropriate capital structure to be utilized in calculating rates, (ii) the appropriate rate of return, (iii) the rate base, including the proper starting rate base, (iv) the rate design and (v) the proper allowance for federal and state income taxes. In addition to the regulatory considerations noted above, it is expected that the interstate common carrier pipeline tariff rates will continue to be constrained by competitive and other market factors. Due to increasing costs of operating its pipelines, management of Genesis is reviewing the need to reach settlement rates with shippers or file for cost-of-service increases. No assurance can be made that Genesis will be successful in obtaining any tariff rate increases.
8 Texas Intrastate Regulation The intrastate common carrier pipeline operations of Genesis 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, used and useful in the services performed, 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 those of Genesis 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. Given this history, although no assurance can be given that the tariffs to be charged by Genesis would ultimately be upheld if challenged, the General Partner believes that the tariffs now in effect can be sustained. Genesis adopted the preexisting tariffs in effect on the date of the closing of Genesis's initial public offering of Common Units and has and will increase the tariffs as needed to adequately recover the costs of operating the pipelines. Pipeline Safety Regulation Genesis's 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. Genesis has conducted hydrostatic testing of most segments of its pipeline systems. 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. In 2001, The Office of Pipeline Safety of the DOT issued new regulations for Pipeline Integrity Management for High Consequence Areas. High Consequence Areas are 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 close proximity of all of Genesis' pipelines to water crossings and populated areas, virtually all of Genesis's pipeline segments are subject to this regulation. The regulation requires Genesis to prepare an Integrity Management Plan ("IMP") 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 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. Testing will involve one or more types of tests. The testing schedule requires a baseline assessment to be completed within seven years, with the 50% highest risk pipeline segments assessed within forty-two months. Reassessment is then required every five years. Genesis has performed its initial review of risk factors and ranking of its pipeline segments. Genesis is in the process of determining the timing of the testing schedule and the methods that will be used for the testing. The method of testing for each segment can vary, with the cost of testing varying with the method used. If the results of the testing indicate that the integrity of the pipeline is compromised, Genesis will be required to make repairs for which the cost cannot be determined until the nature of any problems are known. No assurance can be given that the cost of testing and the required repairs identified will not be material costs to Genesis that may not be fully recoverable by tariff increases. 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,
9 states vary considerably in their authority and capacity to address pipeline safety. Genesis does not anticipate any significant problems in complying with applicable state laws and regulations in those states in which it operates. Genesis's crude oil pipelines are also subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. Management believes that Genesis's crude oil pipelines have been operated in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. In general, the General Partner expects to increase Genesis's 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, Genesis does expect to spend at least $0.8 million over the next seven years related to testing under the IMP. The Partnership cannot estimate at this time any expenditures that may be necessary as a result of that testing. Trucking regulation Genesis operates its 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. Genesis is also subject to OSHA with respect to its trucking operations. Commodities regulation Genesis's 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 Exchange Act of 1934. Although management of the General Partner believes that its expectations regarding future events are based on reasonable assumptions, no assurance can be made that the Partnership's 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: * changes in regulations; * the Partnership's success in obtaining additional lease barrels; * changes in crude oil production volumes (both world-wide and in areas in which the Partnership has operations); * developments relating to possible acquisitions or business combination opportunities; * volatility of crude oil prices and grade differentials; * the success of the risk management activities; * credit requirements by the counterparties; * the costs of obtaining liability and property insurance at a reasonable cost; * the Partnership's ability in the future to generate sufficient amounts of Available Cash to permit the payment to unitholders of a quarterly distribution; * any requirements for testing or changes in the Mississippi pipeline system as a result of the oil spill that occurred there in December 1999; * any fines and penalties federal and state regulatory agencies may impose in connection with the oil spill that would not be reimbursed by insurance; * the costs of testing under the IMP and any repairs required as a result of that testing; * the Partnership's success in increasing tariff rates on its common carrier pipelines; * results of current or threatened litigation; and
10 * 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 the Partnership, or persons acting on the Partnership's behalf, are expressly qualified in their entirety by the foregoing cautionary statements. Item 2. Properties The Partnership owns and operates three common carrier crude oil pipeline systems. The pipelines and related gathering systems consist of the 703-mile Texas system, the 114-mile Jay System extending between Florida and Alabama, and the 261-mile Mississippi System extending between Mississippi and Louisiana. The Partnership also owns approximately 1.5 million barrels of storage capacity associated with the pipelines. These storage capacities include approximately 0.2 million barrels each on the Mississippi and Jay Systems and 1.1 million barrels on the Texas System, primarily at the Satsuma terminal in Houston, Texas. Additionally, the Partnership leases 0.2 million barrels of storage capacity on the Texas System. In addition to transporting crude oil by pipeline, the Partnership transports crude oil through a fleet of leased tractors and trailers. At December 31, 2001, the trucking fleet consisted of approximately 75 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. The Partnership leases approximately 27,000 square feet of office space in Houston, Texas, for its corporate office. This lease expires in 2005; however, the Partnership and the landlord each have an option to terminate the lease at December 31, 2003. Should Genesis terminate the lease at that date, it will owe the landlord a penalty of approximately $0.3 million. Item 3. Legal Proceedings The Partnership is involved from time to time in various claims, lawsuits and administrative proceedings incidental to its business. In the opinion of management of the General Partner, 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 21 of Notes to Consolidated Financial Statements. Item 4. Submission of Matters to a Vote of Security Holders None.
11 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. <TABLE> <CAPTION> Price Range ------------------ Cash High Low Distributions <F1> -------- ------- ----------------- 2001 - ---- <s> <c> <c> <c> First Quarter $ 6.1000 $3.5000 $0.20 Second Quarter $ 6.0000 $4.1500 $0.20 Third Quarter $ 6.9200 $4.2000 $0.20 Fourth Quarter $ 7.0000 $2.3300 $0.20 2000 - ---- First Quarter $10.5625 $7.5000 $0.50 Second Quarter $ 9.8750 $4.8750 $0.50 Third Quarter $ 8.0000 $5.6875 $0.50 Fourth Quarter $ 7.0000 $3.2500 $0.78 <F2> - ---------------------------- <FN> <F1> Cash distributions are shown in the quarter paid and are based on the prior quarter's activities. <F2> Includes a special distribution of $0.28 per unit paid in conjunction with the restructuring of the Partnership that was approved by Common Unitholders on December 7, 2000. </FN> </TABLE> At December 31, 2001, there were 8,625,000 Common Units outstanding. As of December 31, 2001, 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, which was paid on February 14, 2001. In 2001, the Partnership announced that it would not pay a distribution for the fourth quarter of 2001, which would normally have been paid in February 2002. The payment of distributions in the future is dependent upon the Partnership's ability to generate sufficient Available Cash and whether the Partnership would violate covenants in the Partnership's credit agreement by making such distributions. The Partnership does not expect to have sufficient Available Cash to pay any distributions during 2002. 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.
12 Item 6. Selected Financial Data The table below includes selected financial data for the Partnership for the years ended December 31, 2001, 2000, 1999 and 1998 and 1997 (in thousands, except per unit and volume data). <TABLE> <CAPTION> Year Ended December 31, ---------------------------------------------------------- 2001 2000 1999 1998 1997 ---------- ---------- ---------- ---------- ---------- <s> <c> <c> <c> <c> <c> Income Statement Data: Revenues: Gathering & marketing revenues $3,326,003 $4,309,614 $2,144,646 $2,216,942 $3,354,939 Pipeline revenues 14,195 14,940 16,366 16,533 17,989 ---------- ---------- ---------- ---------- ---------- Total revenues 3,340,198 4,324,554 2,161,012 2,233,475 3,372,928 Cost of sales: Crude cost 3,293,836 4,281,567 2,118,318 2,184,529 3,331,184 Field operating costs 15,649 13,673 11,669 12,778 12,107 Pipeline operating costs 10,897 8,652 8,161 7,971 6,016 ---------- ---------- ---------- ---------- ---------- Total cost of sales 3,320,382 4,303,892 2,138,148 2,205,278 3,349,307 ---------- ---------- ---------- ---------- ---------- Gross margin 19,816 20,662 22,864 28,197 23,621 General and administrative expenses 11,691 10,942 11,649 11,468 8,557 Depreciation and amortization 7,546 8,032 8,220 7,719 6,300 Impairment of long-lived assets 45,061 - - - - Nonrecurring charges 1,500 1,387 - 373 - ---------- ---------- ---------- ---------- ---------- Operating income (loss) (45,982) 301 2,995 8,637 8,764 Interest income (expense), net (527) (1,010) (929) 154 1,063 Change in fair value of derivatives 2,259 - - - - Other income (expense) 167 1,148 849 28 21 ---------- ---------- ---------- ---------- ---------- Income (loss) before minority interest and cumulative effect of change in accounting principle (44,083) 439 2,915 8,819 9,848 Minority interests (4) 258 583 1,763 1,968 ---------- ---------- ---------- ---------- ---------- Income (loss) before cumulative effect of change in accounting principle (44,079) 181 2,332 7,056 7,880 Cumulative effect of change in accounting principle, net of minority interest effect 467 - - - - ---------- ---------- ---------- ---------- ---------- Net income (loss) $ (43,612) $ 181 $ 2,332 $ 7,056 $ 7,880 ========== ========== ========== ========== ========== Net income (loss) per common unit- basic and diluted: Income (loss) before cumulative effect of change in accounting principle $ (5.01) $ 0.02 $ 0.27 $ 0.80 $ 0.90 Cumulative effect of change in accounting principle 0.05 - - - - ---------- ---------- ---------- ---------- ---------- Net income (loss) $ (4.96) $ 0.02 $ 0.27 $ 0.80 $ 0.90 ========== ========== ========== ========== ========== Cash distributions per common unit: $ 0.80 $ 2.28 $ 2.00 $ 2.00 $ 1.66 Balance Sheet Data (at end of period): Current assets $ 182,100 $ 350,604 $ 274,717 $ 185,216 $ 232,202 Total assets 230,113 449,343 380,592 297,173 331,114 Long-term liabilities 13,900 - 3,900 15,800 - Minority interests 515 520 30,571 29,988 28,225 Partners' capital 32,009 82,615 53,585 67,871 78,351 Other Data: Maintenance capital expenditures <F1> $ 1,882 $ 1,685 $ 1,682 $ 1,509 $ 3,785 EBITDA <F2> $ 9,522 $ 9,481 $ 12,064 $ 16,384 $ 15,085 Volumes (bpd): Gathering and marketing: Wellhead 84,677 99,602 93,397 114,400 104,506 Bulk and exchange 270,845 297,776 242,992 325,468 346,760 Pipeline 84,686 86,458 94,048 85,594 89,117 - ------------------------ <FN> <F1> The General Partner estimates that capital expenditures necessary to maintain the existing asset base at current operating levels will be approximately $2 million each year. <F2> EBITDA (earnings before interest expense, income taxes, depreciation and amortization and minority interests and impairment) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations). </FN> </TABLE>
13 The table below summarizes the Partnership's quarterly financial data for 2001 and 2000 (in thousands, except per unit data). 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 (loss) $ 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) 2000 Quarters ---------------------------------------------- First Second Third Fourth ---------- ---------- ---------- ---------- Revenues $1,001,843 $1,194,896 $1,093,032 $1,034,783 Gross margin $ 4,299 $ 5,042 $ 6,904 $ 4,417 Operating income (loss) $ (403) $ (287) $ 2,071 $ (1,654) Net income (loss) $ (581) $ 10 $ 1,520 $ (768) Net income (loss) per Common Unit-basic and diluted $ (0.07) $ 0.00 $ 0.17 $ (0.09) 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: * Critical Accounting Policies * Results of Operations * Liquidity and Capital Resources * Other Matters * Outlook Critical Accounting Policies Gathering and marketing revenue is 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. Derivative transactions, which 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. The change in fair value is recorded in earnings for the period. For the Partnership, derivative contracts consist of futures positions and contracts for the purchase and sale of crude oil in the future that include a stated volume and pricing mechanism. Many of the Partnership's contracts for leasehold purchases do not meet the requirement to be treated as derivative contracts because the contracts do not include a stated volume. When events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, the Partnership compares 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, the Partnership records
14 an impairment charge to reflect the asset at fair value. Fair value is determined by discounting the future estimated cash flows. Crude oil inventories held for sale are valued at the lower of average cost or market. 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, ------------------------------------ 2001 2000 1999 ---------- ---------- ---------- Revenues Gathering & marketing $3,326,003 $4,309,614 $2,144,646 Pipeline $ 14,195 $ 14,940 $ 16,366 Gross margin Gathering & marketing $ 16,518 $ 14,374 $ 14,659 Pipeline $ 3,298 $ 6,288 $ 8,205 General and administrative expenses $ 11,691 $ 10,942 $ 11,649 Depreciation and amortization $ 7,546 $ 8,032 $ 8,220 Impairment of long-lived assets $ 45,061 $ - $ - Nonrecurring charges $ 1,500 $ 1,387 $ - Operating income (loss) $ (45,982) $ 301 $ 2,995 Interest income (expense), net $ (527) $ (1,010) $ (929) Change in fair value of derivatives $ 2,259 $ - $ - Cumulative effect of adoption of FAS 133 $ 467 $ - $ - Net gain on disposal of surplus assets $ 167 $ 1,148 $ 849 The profitability of Genesis depends to a significant extent upon its 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 generally 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 the gathering and marketing business, Genesis seeks to purchase and sell crude oil at points along the Distribution Chain where it can achieve positive gross margins. Genesis generally purchases crude oil at prevailing prices from producers at the wellhead under short-term contracts and then transports the crude along the Distribution Chain for sale to or exchange with customers. Prior to the first quarter of 2002, Genesis purchased crude oil in bulk at major pipeline terminal points. Additionally, Genesis enters into exchange transactions with third parties. Genesis generally enters into exchange transactions only when the cost of the exchange is less than the alternate cost that would be incurred in transporting or storing the crude oil. In addition, Genesis often exchanges one grade of crude oil for another to maximize margins or meet contract delivery requirements. These bulk and exchange transactions are characterized by large volumes and narrow profit margins on purchases and sales.
15 Generally, as Genesis purchases crude oil, it simultaneously establishes a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX. Through these transactions, Genesis seeks 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 the policy of Genesis not to hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes. Pipeline revenues and gross margins are primarily a function of the level of throughput and storage activity and are generated by the difference between the regulated published tariff and the fixed and variable costs of operating the pipeline. Changes in revenues, volumes and pipeline operating costs, therefore, are relevant to the analysis of financial results of Genesis' pipeline operations and are addressed in the following discussion of pipeline operations of Genesis. 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: * 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; * 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; * a decrease of $0.4 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 * 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 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 $0.7 million as a result of small declines in throughput and average tariffs. Revenues from sales of pipeline loss allowance barrels decreased $0.3 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.
16 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. As a result in the reduction in the carrying value of these assets, depreciation expense will be reduced in future years by approximately $1.5 million. Non-recurring charge. In 2001, the Partnership recorded a non- recurring charge of $1.5 million related to environmental matters, including the Mississippi spill that occurred in December 1999. In 2000, non-recurring 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 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 fair value of the Partnership's net asset for derivatives had increased by $2.3 million for the year ended December 31, 2001. The fair value of derivative contracts at December 31, 2001, was determined using the sources for fair value as shown in the table below (in thousands).
17 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 $ 1,314 $ - $ - $ 1,314 Prices provided by other external sources - - - - Prices based on models and other valuation methods 645 105 - 750 -------- ------ -------- ---------- Total $ 1,959 $ 105 $ - $ 2,064 ======== ====== ======== ========== The consolidated balance sheet includes $5.5 million in other current assets and $3.5 million in accrued liabilities as a result of recording the fair value of derivatives. The Partnership has not designated any of its derivatives as hedging instruments. 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. Year Ended December 31, 2000 Compared with Year Ended December 31, 1999 Gross margin. Gathering and marketing gross margins decreased $0.3 million or 2% to $14.4 million for the year ended December 31, 2000, as compared to $14.7 million for the year ended December 31, 1999. During 2000, the Partnership recognized an unrealized loss on written option contracts of $0.6 million. This loss, when combined with several other factors, netted the decrease of $0.3 million. The other factors affecting gross margin were: * an increase of 18 percent in wellhead, bulk and exchange purchase volumes between 1999 and 2000, resulting in an increase in gross margin of $5.0 million; * a 5 percent decline 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 reduced gross margin by $1.6 million; * an increase of $1.1 million in credit costs due to the increase in purchase volumes and a 57 percent increase in the average absolute price level of crude oil; and * an increase of $2.0 million in field operating costs, primarily from a $0.7 million increase in payroll and benefits costs, $0.7 million increase in fuel costs, and $0.6 million increase in rental costs due to the replacement of the tractor/trailer fleet with a leased fleet in the fourth quarter of 2000. The increased payroll-related costs and fuel costs can be attributed to an approximate 16% increase in the number of barrels transported by the Partnership in trucks. Pipeline gross margin decreased $1.9 million or 23% to $6.3 million for the year ended December 31, 2000, as compared to $8.2 million for the year ended December 31, 1999. Pipeline revenues declined $2.7 million as a result of declines in throughput and average tariffs. Throughput declined 8% between the two years, resulting in a revenue decrease of $1.4 million. The average tariff collected on shipments was down 10%, resulting in a revenue decrease of $1.3 million. Revenues from sales of pipeline loss allowance barrels increased $1.3 million as a result of an increase in the amount of pipeline loss allowance that the Partnership is allowed to collect under the terms of its tariffs and higher crude prices. Pipeline operating costs were $0.5 million higher in the 2000 period primarily due to $0.3 million of increased expenditures in areas of spill prevention and employee benefits. General and administrative expenses. General and administrative expenses decreased $0.7 million in 2000 from the 1999 level. In 1999, the Partnership incurred $0.4 million of costs related to Year 2000 remediation. No such costs were incurred in 2000. Additionally, in 2000, the Partnership's costs for professional services and contract labor declined $0.2 million.
18 Depreciation and amortization. Depreciation and amortization expense decreased $0.2 million in 2000 from the 1999 level. This decrease is primarily attributable to a portion of the Partnership's assets becoming fully depreciated in 2000, as well as asset sales in the latter part of 2000. Non-recurring charge. In 2000, the Partnership, after approval by the Common Unitholders, was restructured. The costs associated with this restructuring were charged to expense. These costs, totaling $1.4 million, 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. The payment of these restructuring costs did not affect Available Cash for distributions as cash provided by Salomon under the Distribution Support Agreement was used to fund these costs. Interest income (expense), net. In 2000, the Partnership had an increase in its net interest expense of $0.1 million. Interest expense increased $0.2 million and interest income increased $0.1 million. The increase in interest expense resulted from higher interest rates, offset by lower average debt outstanding. The average interest rate increased 1.93%, resulting in an increase of $0.2 million of interest, while the average debt outstanding declined by $2.0 million, resulting in a decrease in interest expense of $0.1 million. Interest income increased primarily as a result of an increase in interest earned on margin deposits with NYMEX brokers due to higher average balances. The higher balances were required due to increased volatility of crude oil prices in the futures market during 2000. 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 existing fleet was sold, resulting in cash proceeds of $1.8 million and a net gain of $1.0 million. The Partnership sold additional surplus assets, which resulted in proceeds of $0.1 million and a gain of $0.1 million. In 1999, the Partnership sold surplus trailers, receiving cash proceeds of $1.0 million that resulted in a gain of $0.9 million. Liquidity and Capital Resources Cash Flows Net cash provided by operations was $16.8 million for the year ended December 31, 2001 as compared to $4.4 million for the year ended December 31, 2000. The increase in cash flow in 2001 was due primarily to differences in the timing of collection of receivables and payment of liabilities offset by an increase in inventory. Net cash utilized by investing activities was $1.4 million for the year ended December 31, 2001, and net cash provided by investing activities was $0.3 million for the year ended December 31, 2000. In 2001, the Partnership expended $1.9 million for property and equipment additions and received $0.5 million related to the sale of its tractor/trailer fleet. In 2000, the Partnership received cash totaling $1.9 million from the sale of its tractor/trailer fleet and other surplus assets. The Partnership expended $1.7 million on property additions, primarily in its pipeline operations. Net cash used in financing activities was $15.1 million and $5.8 million for the years ended December 31, 2001 and 2000, respectively. In 2001, the Partnership paid regular quarterly distributions to Common Unitholders and the General Partner totaling $7.0 million. The Partnership also paid $0.3 million in 2000 to acquire Common Units in the open market for treasury, some of which were subsequently reissued under the Restricted Unit Plan. In 2001, the Partnership reduced its outstanding net bank borrowings by $8.1 million. Cash flows from financing activities was provided by net borrowings in the amount of $2.1 million under the loan agreement 2000. Capital Expenditures In 2001, the Partnership expended $1.9 million for capital expenditures. The majority of these maintenance capital expenditures related to pipeline operations. In 2000, the Partnership expended $1.7 million for capital expenditures. The majority of these maintenance capital expenditures related to pipeline operations. In 1999, the Partnership expended $2.7 million for capital expenditures, with $1.7 million of that amount for maintenance capital expenditures. Business expansion project expenditures totaled $1.0 million for various small projects.
19 The Partnership has no material commitments to increase capital expenditures for 2002 in excess of the amount expended in 2001. Working Capital and Credit Resources In the Partnership's Form 10-Q for the quarterly period ended September 30, 2001, the Partnership stated that it had engaged Fleet National Bank ("Fleet") to provide a $100 million credit facility. This facility was intended to replace the Master Credit Support Agreement ("Guaranty Facility") with Salomon and the working capital facility with BNP Paribas ("WC Facility"). The Guaranty Facility and WC Facility were both scheduled to expire in the first quarter of 2002. Before the Fleet facility was completed, Enron Corporation ("Enron") announced that it was having financial difficulties. Enron subsequently declared bankruptcy on December 2, 2001. The Partnership announced on December 3, 2001, that it had a $21 million exposure to an Enron subsidiary. On December 4, 2001, Fleet terminated its commitment to provide a credit facility. On December 20, 2001, Enron Reserve Acquisition Corporation made the $21 million payment to the Partnership. Since the Partnership's Guaranty Facility with Salomon and the WC Facility were to expire in the first quarter of 2002, the Partnership entered into negotiations with Citicorp North America Inc. ("Citicorp") for a new facility. Credit Agreement Effective December 19, 2001, GCOLP entered into a two-year $130 million Senior Secured Revolving Credit Facility ("Credit Agreement") with Citicorp. Citicorp and Salomon, the owner of the Partnership's General Partner, are both wholly-owned subsidiaries of Citigroup Inc. The Credit Agreement replaces the Guaranty Facility and the WC Facility. The Credit Agreement has a $25 million sublimit for working capital loans, with the balance of $105 million available for letters of credit to support crude oil purchases. During December 2001 and the first four months of 2002, Salomon is continuing to provide guaranties to the Partnership's counterparties under a transition arrangement between Salomon, Citicorp and the Partnership. For crude oil purchases in December 2001 and January 2002, a maximum of $300 million and $100 million, respectively, in guaranties were available to be issued under the Salomon Guaranty Facility. The key terms of the Credit Agreement are as follows: * Letter of credit fees are based on the Applicable Leverage Level ("ALL") and will range from 2.25% to 4.00%. Through June 30, 2002, the rate is fixed at 3.00%. The ALL is a function of GCOLP's average daily debt to its earnings before interest, depreciation and amortization for the four preceding quarters. * The interest rate on working capital borrowings is also based on the ALL and can range from the prime rate or LIBOR rate plus 2.25% to the prime rate plus 1.25% or LIBOR rate plus 4.50%. Through June 30, 2002, the additional prime rate percentage is fixed at 0.50%. At December 31, 2001, the interest rate on the Partnership's borrowings was 5.25%. * The Partnership will pay a commitment fee on the unused portion of the $130 million commitment. This commitment fee is also based on the ALL and will range from 0.375% to 0.75%. Through June 30, 2002, the commitment fee is fixed at 0.50%. * 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 Credit Agreement) generally includes the Partnership's cash balances, net accounts receivable and inventory, less deductions for certain accounts payable and is calculated monthly. * Collateral under the Credit Agreement consists of all of the Partnership's accounts receivable, inventory, cash accounts, margin accounts and property and equipment. * The Credit Agreement contains covenants requiring a Current Ratio (as defined in the Credit Agreement); a Leverage Ratio (as defined in the Credit Agreement) that decreases throughout
20 2002; an Interest Coverage Ratio (as defined in the Credit Agreement) that increases throughout 2002; and limitations on distributions to Unitholders. Distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage (working capital borrowings plus outstanding letters of credit) under the Credit Agreement for every day of the quarter by at least $20 million. See additional discussion below under "Distributions". Management of the Partnership believes that the terms of the Credit Agreement with Citicorp are similar to the terms that could have been obtained from a third party. The Credit Agreement terms are similar to the terms the Partnership had discussed with other banks. At December 31, 2001, the Partnership had $13.9 million of loans outstanding under the Credit Agreement, with $11.1 million available to be borrowed. At December 31, 2001, the Partnership had $44.6 million and $21.9 million outstanding under Salomon guaranties related to December 2001 and January 2002, respectively, for crude oil purchases. As a result of the Partnership's decision to reduce its level of bulk and exchange transactions, management of the Partnership expects that the Partnership's need for credit support in the form of guaranties or letters of credit to be 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 requiring letters of credit. This situation could in turn adversely affect the Partnership's ability to maintain or increase the level of its purchasing and marketing activities or otherwise adversely affect the Partnership's profitability and Available Cash. Contractual Obligation and Commercial Commitments In addition to the Credit Agreement discussed above, the Partnership has contractual obligations under operating leases as well as commitments to purchase crude oil. The table below summarizes these obligations and commitments at December 31, 2001 (in thousands). <TABLE> <CAPTION> Payments Due by Period ------------------------------------------- Less than 1 - 3 4 - 5 After 5 Contractual Cash Obligations Total 1 Year Years Years Years - ---------------------------- -------- -------- ------- ------ ------ <s> <c> <c> <c> <c> <c> Long-term Debt $ 13,900 $ - $13,900 $ - $ - Operating Leases 19,320 3,989 8,041 3,892 3,398 Unconditional Purchase Obligations <F1> 115,239 107,286 7,953 - - -------- -------- ------- ------ ------ Total Contractual Cash Obligations $148,459 $111,275 $29,894 $3,892 $3,398 ======== ======== ======= ====== ====== <FN> <F1> 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, 2001 were used to value the obligations, such that actual obligations may differ from the amounts included above. </FN> </TABLE> 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. (A full definition of Available Cash is set forth in the Partnership Agreement.) 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 beginning with the distribution for the fourth quarter of 2000, which was paid in February 2001. Under the terms of the Credit Agreement, the Partnership may not pay a distribution for any quarter unless the Borrowing Base exceeded the usage under the Credit Agreement (working capital plus outstanding letters of credit) for every day of the quarter by at least $20 million. For the first quarter of 2002, the Partnership will not pay a distribution as the excess of the Borrowing Base over the usage dropped below $20 million. Management of the Partnership does not anticipate that the Partnership will pay any distributions in 2002 and is unsure when distributions will resume. Should
21 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. In 2001, the Partnership paid regular distributions to the Common Unitholders and the General Partner totaling $0.80 per unit. In 2000, the Partnership paid regular distributions to the Common Unitholders and the General Partner totaling $2.00 per unit and a special distribution of $0.28 per unit to the Common Unitholders as a result of the approval of the Partnership restructuring. In 1999 and 1998, the Partnership paid total distributions of $2.00 per unit to the Common Unitholders and the General Partner. A distribution of $0.20 per unit, applicable to the fourth quarter of 2000, was paid on February 14, 2001 to holders of record on January 31, 2001. The distributions in 2000 were paid utilizing distribution support from Salomon of $12.3 million. In 1999, distribution support of $3.9 million was utilized. The obligation of Salomon to provide distribution support provided for a total of $17.6 million. With the utilization of $1.4 million of distribution support to pay the restructuring costs, all distribution support had been utilized at December 31, 2000. As part of the restructuring in 2000, the obligation of the Partnership to repay this distribution support was eliminated. Other Matters Crude Oil Contamination The Partnership has been named one of the defendants in a complaint filed by Thomas Richard Brown on January 11, 2001, in the 125th District Court of Harris County, cause No. 2001-01176. Mr. Brown, an employee of Pennzoil- Quaker State Company ("PQS"), seeks damages for burns and other injuries suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. On January 17, 2001, PQS filed a Plea in Intervention in the cause filed by Mr. Brown. PQS seeks property damages, loss of use and business interruption. Both plaintiffs claim the fire and explosion was caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. Management of the Partnership believes that the suit is without merit and intends to vigorously defend itself in this matter. Management of the Partnership believes that any potential liability will be covered by insurance. Crude Oil Spill 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 may impose fines and penalties that would not be covered by insurance. See Note 21 of Notes to Consolidated Financial Statement. Termination of Proposed General Partner Sale In May 2001, the Partnership announced that Salomon had entered into a definitive agreement to sell the General Partner to an investment group. This agreement was terminated by Salomon on January 2, 2002. Change to American Stock Exchange Until February 1, 2001, the Common Units of Genesis were traded on the New York Stock Exchange ("NYSE"). In December 2000, the Partnership was notified that it failed to meet the NYSE's continued listing requirements and that the NYSE was commencing delisting procedures. Management of the General Partner submitted a plan to the NYSE to cure the continued listing deficiencies. However, management later concluded that it would be preferable to list the Partnership's Common Units on the AMEX. On January 31, 2001, the Partnership's Common Units ceased to be listed on the NYSE and, on February 1, 2001, began being listed on the AMEX. New Accounting Standards In June, 2001, the FASB issued FAS 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,
22 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 fiscal years beginning after June 15, 2002, with earlier application encouraged. The Partnership is currently evaluating the effect on its financial statements of adopting FAS No. 143 and plans to adopt the statement effective January 1, 2003. In August 2001, the FASB issued FAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets." This statement clarified the financial accounting and reporting for the impairment or disposal of long-lived assets. Impairment is required to be recognized if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows. The impairment loss to be recognized is the difference between the carrying amount and the fair value of the asset. The standard also provides guidance on the accounting for long-lived assets that are held for disposal. This standard is effective for the Partnership beginning January 1, 2002. The Partnership is currently evaluating the effect on its financial statements of adopting FAS No. 144. Outlook Historically, the crude oil gathering and marketing business has been very competitive with thin and volatile profit margins. The ability to generate margin in the crude oil gathering and marketing business is not directly related to the absolute level of crude oil prices but is generated by the difference between the price at which crude oil is sold and the price paid and other costs incurred in the purchase and transportation of the crude oil, as well as the volume of crude oil available for purchase. In order to maximize gross margin, management has been and will continue to analyze all aspects of its gathering and marketing business in order to make decisions associated with managing its marketing operations, field operations and administrative support. Another factor affecting crude oil gathering and marketing gross margins is changes in the domestic production of crude oil. Short-term and long-term crude oil 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 Genesis and its competitors. During 1999, 2000 and 2001, crude oil prices were marked by significant volatility which made it very difficult to estimate the amount of crude oil available to purchase. Management expects to continue to be subject to volatility and long-term declines in the availability of crude oil production for purchase by Genesis. Genesis' gathering and marketing operations are also impacted by credit support costs in the form of guaranties and letters of credit. As stated above, gathering and marketing gross margins are not tied to the absolute prices of crude oil. In contrast, the per barrel cost of credit is a function of the absolute price of crude oil, such that, as crude oil prices rise, credit costs increase. In anticipation of the expiration of the $300 million Guaranty Facility and the $25 million WC Facility during the first quarter of 2002, management began making changes to its business model in order to be able to operate with a $100 million revolving credit facility with a higher per barrel cost. These changes resulted in a substantial decrease in the Partnership's bulk and exchange activity by the end of 2001. Additionally, the Partnership began reviewing its wellhead purchase contracts to determine whether margins under those contracts would support higher credit costs per barrel. In some cases where contract terms could not be renegotiated to improve margins after considering the higher cost of credit, contracts were cancelled. As a result of substantially eliminating its bulk and exchange volumes, management of the Partnership expects significant declines in its gathering and marketing gross margin during 2002. Had the Partnership continued to engage in its bulk and exchange activity, management believes that increases in the related cost of credit would have substantially offset the gross margin provided by that activity. The cost of credit is impacted by the extent to which trade counterparties require credit support. Historically, only a small minority of the volumes of crude oil purchased from producers at the wellhead required credit support. Since the Enron collapse, while amounts purchased from producers requiring trade credit still represent less than half of all amounts purchased, the amount of wellhead purchases requiring trade credit has increased substantially. Management of the Partnership expect that credit support requirements from producers will decline over time as producers adjust their credit demands to be more consistent with the credit risk. However, no assurances can be made that such credit requirements will decrease or that such credit support requirements will not increase over time. Like the gathering and marketing operations, prospects for Genesis' pipeline operations also are impacted by production declines. Declining production in the areas surrounding Genesis' pipelines have reduced tariff
23 revenues while costs are expected either to remain fixed or to increase due to various conditions, including increasing insurance costs, new pipeline integrity management regulations and commercial and residential development over our pipeline right of ways. Consequently, pipeline gross margins are expected to decline unless Genesis obtains substantial increases in its tariff rates. Genesis intends to pursue increases in its tariff rates; however, it is uncertain whether such increases can be obtained and whether such increases will be sufficient to offset production declines in the pipeline operating areas and any increased maintenance and operating costs related to its pipelines. As stated above, during late 2001 the Partnership was executing a plan to change its business model to obtain a $100 million revolving credit facility to replace its existing credit facilities. The impact on credit markets caused by the collapse of Enron, the Partnership's announced exposure to Enron, and the uncertainty of the Partnership's near term credit support requirements led to the termination of negotiations for the replacement credit facility described above. Instead, Genesis obtained the $130 million Credit Agreement. The Credit Agreement includes certain restrictive covenants that require the Partnership to meet certain tests before it will be able to make distributions to its unitholders. See Credit Agreement section of Liquidity and Capital Resources above. Based on the factors described above, management does not believe that it is feasible for Genesis to restore the distribution and grow it further, relying solely on internal growth. Genesis must make accretive acquisitions of qualified MLP assets to restore the distribution and increase value for Genesis' unitholders. Management believes that the best way to position Genesis to make acquisitions is to find a strategic partner with the ability to contribute qualified assets or infuse equity capital to make such acquisitions. Management of the General Partner will continue its efforts to explore strategic opportunities to grow the asset base of the Partnership in order to restore and increase distributions to the unitholders. No assurance can be made that the Partnership will be able to grow the Partnership's asset base to offset reductions in gross margin and Available Cash that may result from the Partnership's transition to a new credit facility or production declines. In order to improve the effectiveness of any strategic opportunities and to meet its obligations under the Credit Agreement, the Partnership is evaluating opportunities to dispose of underperforming assets and increase operating income by reducing nonessential expenditures. Based on anticipated business conditions for 2002, including certain restrictive covenants in Genesis' Credit Agreement, the Partnership currently does not expect to pay any cash distributions to unitholders during 2002. Item 7a. Quantitative and Qualitative Disclosures about Market Risk The Partnership's primary price risk relates to the effect of crude oil price fluctuations on its inventories and the fluctuations each month in grade and location differentials and their affect on future contractual commitments. The Partnership utilizes NYMEX commodity based futures contracts, forward contracts, swap agreements and option contracts to hedge its exposure to these market price fluctuations. Management believes the hedging program has been effective in minimizing overall price risk. At December 31, 2001, the Partnership used forward contracts exclusively in its hedging program with the latest contract being settled in January 2002. 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) 214 Carrying value $ 3,662 Fair value $ 4,132 Commodity Forward Contracts: Contract volumes (1,000 bbls) 1,900 1,900 Weighted average price per bbl $ 17.98 $ 18.16 Contract value (in thousands) $34,151 $34,493 Mark-to-market change (in thousands) $ 2,599 $ 2,594 ------- ------- Market settlement value (in thousands) $36,750 $37,087 ======= =======
24 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, 2001 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 32. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures None. Part III Item 10. Directors and Executive Officers of the Registrant The Partnership does 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 has established a committee (the "Audit Committee") consisting of individuals who are neither officers nor employees of the General Partner or any affiliate of the General Partner. 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 the external financial reporting of the Partnership, recommends engagement of the Partnership's independent accountants, and reviews the adequacy of the Partnership's 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 ------------------ --- ------------------------------------------- A. Richard Janiak 55 Director and Chairman of the Board Mark J. Gorman 47 Director, Chief Executive Officer and President Herbert I. Goodman 79 Director J. Conley Stone 70 Director Robert T. Moffett 50 Director Susan O. Rheney 42 Director Ross A. Benavides 48 Chief Financial Officer, General Counsel and Secretary Ben F. Runnels 61 Vice President, Trucking Operations Kerry W. Mazoch 55 Vice President, Crude Oil Acquisitions Karen N. Pape 44 Vice President and Controller A. Richard Janiak has served as Director and Chairman of the Board of the General Partner since June 1999. He is a Managing Director of Salomon Smith Barney Inc., where he has served in various investment banking and management positions since 1970. 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. 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. Mr. Goodman's term as a Director will expire December 31, 2002.
25 Mr. 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. Mr. Stone's term as a Director will expire December 31, 2002. Robert T. Moffett became a Director of the General Partner in February 1999. He has held the position of Vice President, General Counsel and Secretary of Howell since December 1996. He was Vice President and General Counsel of Howell from January 1995 to December 1996. Mr. Moffett joined Howell as General Counsel in September 1992. Effective March 31, 2002, Mr. Moffett has resigned as a Director of the General Partner. 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, and American Plumbing and Mechanical, Inc., where she serves on the audit and compensation committees. Ms. Rheney's term as a Director will expire June 30, 2003. 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. Ben F. Runnels has served as Vice President, Trucking Operations of the General Partner since December 1996. He held the position of General Manager, Operations with Basis and its predecessor, Phibro USA, for the previous four years. 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 were required for those persons, the General Partner believes that during 2001 its officers and directors complied with all applicable filing requirements in a timely manner. Representatives of Salomon and officers of the General Partner do not receive any additional compensation for serving Genesis Energy, L.L.C., as members of the Board of Directors or any of its committees. Each of the independent directors receives an annual fee of $30,000. Item 11. Executive Compensation Under the terms of the Partnership Agreement, the Partnership is 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 2001, 2000 and 1999 to the Chief Executive Officer and each of Genesis' four other most highly compensated executive officers (the "Named Officers").
26 <TABLE> <CAPTION> 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 $ $ $ <F1> $ $ - --------------------------- ---- ------- ------ ------------ ------------ ------------ <s> <c> <c> <c> <c> <c> <c> Mark J. Gorman 2001 270,000 56,814 - - 10,200 <F2> Chief Executive Officer 2000 270,000 50,000 - - 10,200 <F2> and President 1999 236,000 - - - 9,600 <F8> John M. Fetzer <F3> 2001 270,000 56,814 - - 10,200 <F2> Executive Vice President 2000 270,000 50,000 - - 10,200 <F2> 1999 211,000 - - - 9,600 <F8> John P. vonBerg <F4> 2001 270,000 6,814 - - 10,200 <F2> Executive Vice President, 2000 270,000 97,500 - - 10,200 <F2> Trading and Price Risk 1999 410,000 - - - 9,600 <F8> Management Ross A. Benavides 2001 175,000 <F5> 54,785 - - 10,200 <F2> Chief Financial Officer, 2000 150,000 50,000 - - 9,173 <F6> General Counsel and 1999 150,000 - - - 9,586 <F9> Secretary Kerry W. Mazoch 2001 169,000 <F5> 30,720 - - 10,200 <F2> Vice President, Crude 2000 166,000 30,000 - - 10,080 <F7> Oil Acquisitions 1999 166,000 25,000 - - 9,600 <F8> <FN> <F1> 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. <F2> Includes $5,100 of Company-matching contributions to a defined contribution plan and $5,100 of profit-sharing contributions to a defined contribution plan. <F3> Mr. Fetzer resigned as an employee and officer of the Partnership in March 2002. <F4> Mr. vonBerg's employment by the Partnership was terminated in January 2002 as a result of changing business operations to eliminate bulk purchasing. At that time Mr. vonBerg received a payment of $350,000 under the terms of a severance agreement. <F5> Effective March 2001, Mr. Benavides' annual salary was increased to $180,000, and Mr. Mazoch's annual salary was increased to $170,000. <F6> Includes $4,587 of Company-matching contributions to a defined contribution plan and $4,586 of profit-sharing contributions to a defined contribution plan. <F7> Includes $4,980 of Company-matching contributions to a defined contribution plan and $5,100 of profit-sharing contributions to a defined contribution plan. <F8> Includes $4,800 of Company-matching contributions to a defined contribution plan and $4,800 of profit-sharing contributions to a defined contribution plan. <F9> Includes $4,793 of Company-matching contributions to a defined contribution plan and $4,793 of profit-sharing contributions to a defined contribution plan. </FN> </TABLE>
27 Employment and Severance Agreements The Partnership has severance agreements with Mr. Gorman, Mr. Benavides, Mr. Mazoch and Ms. Pape that expire March 31, 2003. The Partnership has an employment agreement with Mr. Runnels that terminates December 31, 2002. The agreement with Mr. Runnels has three remaining optional extension terms of one year each ("Extension Terms"). The agreement with Mr. Runnels includes the following additional provisions: (i) an annual base salary, (ii) eligibility to participate in the Restricted Unit Plan (including the allocation of Initial Restricted Units) and Incentive Compensation Plan described below, (iii) confidential information and noncompetition provisions and (iv) an involuntary termination provision pursuant to which the executive officer will receive severance compensation under certain circumstances. Severance compensation applicable under the employment agreement for an involuntary termination during the Initial Term and Extension Terms (other than a termination for cause, as defined in the agreements) will include payment of the greater of (i) the base salary for the balance of the applicable term, or (ii) one year's base salary then in effect and, in addition, the executive will be entitled to receive incentive compensation payable to the executive in accordance with the Incentive Plan. Upon expiration or termination of the agreement, the confidential information and noncompetition provisions will continue until the earlier of one year after the date of termination or the remainder of the unexpired term, but in no event for less than six months following the expiration or termination. The severance agreements with Mr. Gorman, Mr. Benavides, Mr. Mazoch and Ms. Pape include the following provisions should there be a Change in Control (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): (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. 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
28 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. Item 12. Security Ownership of Certain Beneficial Owners and Management The Partnership knows 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, 2002. <TABLE> <CAPTION> Amount and Nature Name and Address of Beneficial Ownership Percent Title of Class of Beneficial Owner as of January 1, 2002 of Class - ----------------------- ------------------------------------ --------------------- -------- <s> <c> <c> <c> General Partner Interest Genesis Energy, L.L.C. 1 <F1> 100.00 500 Dallas, Suite 2500 Houston, TX 77002 General Partner Interest Salomon Smith Barney Holdings Inc. 1 <F1> 54.00 Salomon Brothers Holding Company Inc. 46.00 333 Greenwich New York, NY 10013 _____________________ <FN> <F1> Salomon owns Genesis Energy, L.L.C. The reporting of the General Partner interest shall not be deemed to be a concession that such interest represents a security. </FN> </TABLE> The following table sets forth certain information as of February 28, 2002, 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. <TABLE> <CAPTION> Amount and Nature of Beneficial Ownership -------------------------------------------- Sole Voting and Shared Voting and Percent Title of Class Name Investment Power Investment Power of Class - -------------------- ------------------ ---------------- ---------------- -------- <s> <c> <c> <c> <c> Genesis Energy, L.P. A. Richard Janiak - - - Common Unit Mark J. Gorman 25,525 - * John P. vonBerg 27,275 - * Herbert I. Goodman 2,000 - * J. Conley Stone 1,000 - * Robert T. Moffett - - - Susan O. Rheney - 700 * John M. Fetzer 24,846 - * Kerry W. Mazoch 8,085 584 * Ross A. Benavides 9,283 - * All directors and executive officers as a group (12 in number) 108,743 1,284 1 - ------------------------- * Less than 1% </TABLE> 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. In January 2002, Mr. vonBerg's employment with the Partnership was terminated as an officer with the Partnership as a result of changing business operations to eliminate bulk purchases. He also resigned as a director of the Partnership. In March 2002, Mr. Fetzer resigned as an employee and officer of the Partnership.
29 Item 13. Certain Relationships and Related Transactions Until December 7, 2000, Salomon and Howell owned 1,163,700 and 991,300 Subordinated OLP Units, respectively, representing a 10.58% and 9.01% limited partner interest in GCOLP. As part of the Partnership restructuring, the Subordinated OLP Units were eliminated. During 1999, Salomon and Howell owned 54% and 46%, respectively, of the General Partner. Effective February 28, 2000, Salomon acquired Howell's 46% interest in the General Partner. Through its control of the General Partner, Salomon has the ability to control the management of the Partnership and GCOLP. Genesis enters into transactions with Salomon and its subsidiaries and the General Partner in the ordinary course of its operations. Additionally, in December 2001 Genesis entered into a credit agreement with Citicorp North America, Inc. ("Citicorp"). Citigroup Inc. is the parent of Salomon and Citicorp. During 2001, these relationships and transactions included: * Sales and purchases of crude oil from a subsidiary of Salomon totaling $29.8 million and $36.7 million, respectively. * 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 $18.1 million. * Provision of guarantees to counterparties by Salomon for GCOLP in the maximum aggregate amount of $300 million. Genesis paid fees to Salomon for guaranty utilization totaling $1.3 million. * Provision of a $130 million working capital and letter of credit facility by Citicorp. See Note 9 of Notes to Consolidated Financial Statements. Genesis paid interest, commitment and other fees to Citicorp in 2001 totaling $0.9 million. At the formation of the Partnership, Salomon entered into a Distribution Support Agreement with the Partnership to provide a maximum of $17.6 million of distribution support in return for Additional Partnership Interests (APIs). The distribution support was provided to the Partnership in 1999 and 2000, and, as part of the restructuring in December 2000, the remaining distribution support was paid to the Partnership and all APIs were eliminated, without payment of consideration, and, as a result, the Partnership's obligation to redeem the APIs was eliminated. Item 14. 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 32. (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 Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 2 of Form 8-A filed January 30, 2001) ** 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the "Operating Partnership") 3.4 Second Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 3.4 to Form 10-K for the year ended December 31, 2000) ** 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. ** 10.2 First Amendment to Purchase & Sale and Contribution & Conveyance Agreement ** 10.3 Master Credit Support Agreement among the Operating Partnership, Salomon Inc and Basis
30 10.4 Non-competition Agreement among Genesis, the Operating Partnership, Salomon Inc, Basis and Howell (incorporated by reference to Exhibit 10.6 to Registration Statement, File No. 333-11545) * 10.5 Severance Agreement between Genesis Energy, L.L.C. and Mark J. Gorman * 10.6 Severance Agreement between Genesis Energy, L.L.C. and Ross A. Benavides * 10.7 Severance Agreement between Genesis Energy, L.L.C. and Kerry W. Mazoch * 10.8 Severance Agreement between Genesis Energy, L.L.C. and Karen N. Pape ** 10.9 Employment Agreement between Genesis Energy, L.L.C. and Ben F. Runnels * 10.10 Extension of Employment Agreement between Genesis Energy, L.L.C. and Ben F. Runnels, 10.11 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) * 10.12 Nineteenth Amendment to Master Credit Support Agreement 10.13 Amended and Restated Restricted Unit Plan (incorporated by reference to Exhibit 10.18 to Form 10-K for the year ended December 31, 1997) * 10.14 Credit Agreement dated as of December 19, 2001, between Genesis Crude Oil, L.P., Genesis Energy, L.L.C., Genesis Energy, L.P., Citicorp North America, Inc., and Certain Financial Institutions * 10.15 First Amendment to the Credit Agreement * 10.16 Second Amendment to the Credit Agreement 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 Notification letter to the SEC from Genesis, dated March 27, 2002, pursuant to Temporary Note 3T to Regulation S-X. - ---------------------- * Filed herewith ** Filed as an exhibit to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1996. (b) Reports on Form 8-K A report on Form 8-K was filed on November 2, 2001, announcing that, upon closing the transaction to transfer ownership of Genesis Energy, L.L.C., the general partner of GELP, from Salomon Smith Barney to GA Partnership, GA Partnership intends to reduce the quarterly distribution from $0.20 per unit to $0.10 per unit effective with the distribution for the fourth quarter of 2001 to be paid in February 2002. (This transfer of ownership did not occur and a report on Form 8-K was filed in January 2002.) A report on Form 8-K was filed on December 3, 2001, announcing that the Partnership had an exposure of approximately $21 million to a subsidiary of Enron Corporation. (The Partnership subsequently collected this receivable from Enron.)
31 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 25th day of March, 2002. GENESIS ENERGY, L.P. (A Delaware Limited Partnership) By: GENESIS ENERGY, L.L.C., 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 25, 2002 - -------------------------- and President Mark J. Gorman (Principal Executive Officer) /s/ Ross A. Benavides Chief Financial Officer, March 25, 2002 - -------------------------- General Counsel and Ross A. Benavides Secretary (Principal Financial Officer) /s/ Karen N. Pape Vice President and Controller March 25, 2002 - -------------------------- (Principal Accounting Officer) Karen N. Pape /s/ A. Richard Janiak Chairman of the Board and March 25, 2002 - -------------------------- Director A. Richard Janiak /s/ Herbert I. Goodman Director March 25, 2002 - -------------------------- Herbert I. Goodman /s/ J. Conley Stone Director March 25, 2002 - -------------------------- J. Conley Stone /s/ Robert T. Moffett Director March 25, 2002 - -------------------------- Robert T. Moffett /s/ Susan O. Rheney Director March 25, 2002 - -------------------------- Susan O. Rheney
32 GENESIS ENERGY, L.P. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page ---- Report of Independent Public Accountants 33 Consolidated Balance Sheets, December 31, 2001 and 2000 34 Consolidated Statements of Operations for the Years Ended December 31, 2001, 2000 and 1999 35 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 36 Consolidated Statements of Partners' Capital for the Years Ended December 31, 2001, 2000 and 1999 37 Notes to Consolidated Financial Statements 38
33 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
34 GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands) December 31, December 31, 2001 2000 -------- -------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 5,777 $ 5,508 Accounts receivable - Trade 160,734 329,464 Related party 1,064 - Inventories 3,737 994 Insurance receivable for pipeline spill costs 1,570 5,527 Other 9,218 9,111 -------- -------- Total current assets 182,100 350,604 FIXED ASSETS, at cost 115,336 113,715 Less: Accumulated depreciation (69,626) (25,609) -------- -------- Net fixed assets 45,710 88,106 OTHER ASSETS, net of amortization 2,303 10,633 -------- -------- TOTAL ASSETS $230,113 $449,343 ======== ======== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Bank borrowings $ - $ 22,000 Accounts payable - Trade 172,848 322,912 Related party 697 4,750 Accrued liabilities 10,144 16,546 -------- -------- Total current liabilities 183,689 366,208 LONG-TERM DEBT 13,900 - COMMITMENTS AND CONTINGENCIES (Note 21) MINORITY INTERESTS 515 520 PARTNERS' CAPITAL Common unitholders, 8,625 units issued; 8,625 and 8,624 units outstanding at December 31, 2001 and 2000, respectively 31,361 80,960 General partner 648 1,661 -------- -------- Subtotal 32,009 82,621 Treasury units, 1 unit at December 31, 2000 - (6) -------- -------- Total partners' capital 32,009 82,615 -------- -------- TOTAL LIABILITIES AND PARTNERS' CAPITAL $230,113 $449,343 ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
32 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts) Year Ended December 31, ---------------------------------- 2001 2000 1999 ---------- ---------- ---------- REVENUES: Gathering and marketing revenues Unrelated parties $3,296,156 $4,274,519 $2,067,451 Related parties 29,847 35,095 77,195 Pipeline revenues 14,195 14,940 16,366 ---------- ---------- ---------- Total revenues 3,340,198 4,324,554 2,161,012 COST OF SALES: Crude costs, unrelated parties 3,257,137 4,150,888 2,043,506 Crude costs, related parties 36,699 130,679 74,812 Field operating costs 15,649 13,673 11,669 Pipeline operating costs 10,897 8,652 8,161 ---------- ---------- ---------- Total cost of sales 3,320,382 4,303,892 2,138,148 ---------- ---------- ---------- GROSS MARGIN 19,816 20,662 22,864 EXPENSES: General and administrative 11,691 10,942 11,649 Depreciation and amortization 7,546 8,032 8,220 Impairment of long-lived assets 45,061 - - Nonrecurring charges 1,500 1,387 - ---------- ---------- ---------- OPERATING INCOME (LOSS) (45,982) 301 2,995 OTHER INCOME (EXPENSE): Interest income 166 259 156 Interest expense (693) (1,269) (1,085) Change in fair value of derivatives 2,259 - - Net gain on disposal of surplus assets 167 1,148 849 ---------- ---------- ---------- Income (loss) before minority interests and cumulative effect of change in accounting principle (44,083) 439 2,915 Minority interests (4) 258 583 ---------- ---------- ---------- Income (loss) before cumulative effect of change in accounting principle (44,079) 181 2,332 Cumulative effect of change in accounting principle, net of minority interest effect 467 - - ---------- ---------- ---------- NET INCOME (LOSS) $ (43,612) $ 181 $ 2,332 ========== ========== ========== NET INCOME PER COMMON UNIT- BASIC AND DILUTED: Income (loss) before cumulative effect of change in accounting principle $ (5.01) $ 0.02 $ 0.27 Cumulative effect of change in accounting principle 0.05 - - ---------- ---------- ---------- Net income (loss) $ (4.96) $ 0.02 $ 0.27 ========== ========== ========== WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING 8,624 8,617 8,604 ========== ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
36 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, ------------------------------ 2001 2000 1999 --------- -------- -------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ (43,612) $ 181 $ 2,332 Adjustments to reconcile net income to net cash provided by operating activities - Depreciation 6,228 6,714 6,832 Amortization of intangible assets 1,318 1,318 1,388 Impairment of long-lived assets 45,061 - - Cumulative effect of change in accounting principle (467) - - Change in fair value of derivatives (2,259) - - Gain on disposal of surplus assets (167) (1,148) (849) Minority interests equity in earnings (losses) (4) 258 583 Restructuring costs - 1,387 - Other noncash charges 1,605 1,801 1,459 Changes in components of working capital - Accounts receivable 167,666 (80,905) (76,325) Inventories (2,743) (590) 1,562 Other current assets 3,565 4,436 (15,784) Accounts payable (154,117) 74,316 75,003 Accrued liabilities (5,230) (3,355) 13,861 --------- -------- -------- Net cash provided by operating activities 16,844 4,413 10,062 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment (1,882) (1,685) (2,717) Change in other assets - 11 416 Proceeds from sales of assets 453 1,942 1,012 --------- -------- -------- Net cash (used in) provided by investing Activities (1,429) 268 (1,289) CASH FLOWS FROM FINANCING ACTIVITIES: Bank borrowings, net (8,100) 2,100 4,100 Distributions to common unitholders (6,898) (19,645) (17,206) Distributions to General Partner (141) (352) (352) Distributions to minority interest owner (1) - - Issuance of additional partnership interests - 13,702 3,900 Payment of restructuring costs - (1,387) - Purchase of treasury units, net (6) (255) (261) --------- -------- -------- Net cash used in financing activities (15,146) (5,837) (9,819) Net increase (decrease) in cash and cash equivalents 269 (1,156) (1,046) Cash and cash equivalents at beginning of period 5,508 6,664 7,710 --------- -------- -------- Cash and cash equivalents at end of period $ 5,777 $ 5,508 $ 6,664 ========= ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
37 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (In thousands) Partners' Capital --------------------------------- Common General Treasury Unitholders Partner Units Total -------- ------ ----- -------- Partners' capital, December 31, 1998 $ 66,832 $1,357 $(318) $ 67,871 Net income 2,286 46 - 2,332 Cash distributions (17,206) (352) - (17,558) Purchase of treasury units - - (261) (261) Issuance of treasury units to Restricted Unit Plan participants - - 539 539 Excess of expense over cost of treasury units issued for Restricted Unit Plan 662 - - 662 -------- ------ ----- -------- 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 ======== ====== ===== ======== The accompanying notes are an integral part of these consolidated financial statements.
38 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, L.L.C. (the "General Partner") and owns a 2% general partner interest in GELP. The General Partner is owned by Salomon Smith Barney Holdings Inc. ("Salomon") and Salomon Brothers Holding Company Inc., in 54% and 46% interests, respectively. 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 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, 2001 and 2000 for GELP and its results of operations, cash flows and changes in partners' capital for the years ended December 31, 2001, 2000 and 1999. 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 approximately 80,000 barrels per day 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 generally accepted accounting principles 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.
39 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 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. 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. 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. Other Assets Other assets consist primarily of intangibles and goodwill. Intangibles include a covenant not to compete, which is being amortized over five years. Goodwill of $9.4 million represents the excess of purchase price over fair value of the net assets acquired for acquisitions accounted for as purchases and was being amortized over a period of 20 years. In 2001, the Partnership recorded an impairment charge for goodwill, reducing the unamortized balance to zero. See Notes 8 and 11. 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. 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." Derivative transactions, which include future positions on the New York Mercantile Exchange ("NYMEX") as well as forward contracts, are recorded on the balance sheet as assets or liabilities based on the measure of the derivative's fair value. The change in fair value is recorded in earnings for the period. 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 8,623,741, 8,616,744 and 8,604,352 for the
40 years ended December 31, 2001, 2000 and 1999, 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 fiscal years beginning after June 15, 2002, with earlier application encouraged. The Partnership is currently evaluating the effect on its financial statements of adopting SFAS No. 143 and plans to adopt the statement effective January 1, 2003. In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment on Disposal of Long-Lived Assets." This statement clarified the financial accounting and reporting for the impairment or disposal of long-lived assets. Impairment is required to be recognized if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows. The impairment loss to be recognized is the difference between the carrying amount and the fair value of the asset. The standard also provides guidance on the accounting for long-lived assets that are held for disposal. This standard is effective for the Partnership beginning January 1, 2002. The Partnership is currently evaluating the effect on its financial statements of adopting SFAS No. 144. 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. BP Amoco Corporation subsidiaries and Enron Corporation subsidiaries accounted for 10.6% and 14.1% of total revenues in 2001, respectively. Genesis received payment for all sales to Enron Corporation subsidiaries. No customer accounted for more than 10% of the Partnership's revenues in 2000 or 1999. 6. Inventories Inventories consisted of the following (in thousands). December 31, ------------------ 2001 2000 -------- -------- Crude oil inventories, at lower of cost or market $ 3,662 $ 847 Fuel and supplies inventories, at lower of cost or Market 75 147 -------- -------- Total inventories $ 3,737 $ 994 ======== ======== 7. Fixed Assets Fixed assets consisted of the following (in thousands). December 31, ------------------ 2001 2000 -------- -------- Land and buildings $ 3,718 $ 3,718 Pipelines and related assets 98,085 96,670 Vehicles and transportation equipment 1,808 1,894 Office equipment, furniture and fixtures 2,809 2,569 Other 8,916 8,864 -------- -------- 115,336 113,715 Less - Accumulated depreciation (69,626) (25,609) -------- -------- Net fixed assets $ 45,710 $ 88,106 ======== ========
41 Depreciation expense was $6,228,000, $6,714,000 and $6,832,000 for the years ended December 31, 2001, 2000 and 1999, 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, ------------------ 2001 2000 -------- -------- Goodwill $ 9,401 $ 9,401 NYMEX seats 1,203 1,203 Covenant not to compete 4,238 4,238 Other 47 51 14,889 14,893 Less - Accumulated amortization (12,586) (4,260) -------- -------- Net other assets $ 2,303 $ 10,633 ======== ======== Amortization expense was $1,318,000, $1,318,000 and $1,388,000 for the years ended December 31, 2001, 2000 and 1999, respectively. In 2001, the Partnership recorded an impairment charge related to goodwill of $7,012,000. The unamortized balance of goodwill at December 31, 2001 is zero. See Note 11. In February 2002, the Partnership sold its NYMEX seats for a total of $1,700,000. 9. Credit Resources and Liquidity 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 owner of the partnership's General Partner, are both wholly-owned subsidiaries of Citigroup Inc. The Credit Agreement replaces the Guaranty Facility and the WC Facility. The Credit Agreement has a $25 million sublimit for working capital loans, with the balance of $105 million available for letters of credit to support crude oil purchases. During December 2001 and the first four months of 2002, Salomon is continuing to provide guaranties to the Partnership's counterparties under a transition arrangement between Salomon, Citicorp and the Partnership. For crude oil purchases in December 2001 and January 2002, a maximum of $300 million and $100 million, respectively, in guaranties were available to be issued under the Salomon guaranty facility. The key terms of the Credit Agreement are as follows: * Letter of credit fees are based on the Applicable Leverage Level ("ALL") and will range from 2.25% to 4.00%. Through June 30, 2002, the rate is fixed at 3.00%. The ALL is a function of GCOLP's average daily debt to its earnings before interest, depreciation and amortization for the four preceding quarters. * The interest rate on working capital borrowings is also based on the ALL and can range from the prime rate or LIBOR rate plus 2.25% to the prime rate plus 1.25% or LIBOR rate plus 4.50%. Through June 30, 2002, the additional prime rate percentage is fixed at 0.50%. At December 31, 2001, the interest rate on the Partnership's borrowings was 5.25%. * The Partnership will pay a commitment fee on the unused portion of the $130 million commitment. This commitment fee is also based on the ALL and will range from 0.375% to 0.75%. Through June 30, 2002, the commitment fee is fixed at 0.50%. * 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 Credit Agreement) generally includes the Partnership's cash balances, net accounts receivable and inventory, less deductions for certain accounts payable and is calculated monthly.
42 * Collateral under the Credit Agreement consists of all of the Partnership's accounts receivable, inventory, cash accounts, margin accounts and property and equipment. * The Credit Agreement contains covenants requiring a Current Ratio (as defined in the Credit Agreement); a Leverage Ratio (as defined in the Credit Agreement) that decreases throughout 2002; an Interest Coverage Ratio (as defined in the Credit Agreement) that increases throughout 2002; and limitations on distributions to Unitholders. Distributions to Unitholders and the General Partner can only be made if the Borrowing Base exceeds the usage (working capital borrowings plus outstanding letters of credit) under the Credit Agreement for every day of the quarter by at least $20 million. See additional discussion below under "Distributions". At December 31, 2001, the Partnership had $13.9 million of loans outstanding under the Credit Agreement, with $11.1 million available to be borrowed. The outstanding loan balance is to be repaid by December 31, 2003; however, due to the revolving nature of the loans, additional borrowings and periodic repayments and re-borrowings may be made until that date. At December 31, 2001, the Partnership had $44.6 million and $21.9 million outstanding under Salomon guaranties related to December 2001 and January 2002, respectively, for crude oil purchases. Credit Availability As a result of the Partnership's decision to reduce its level of bulk and exchange transactions, management of the Partnership expects that the Partnership's need for credit support in the form of guaranties or letters of credit to be 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 requiring letters of credit which could restrict the Partnership's gathering and marketing activities due to the limitations of the Credit Agreement and Borrowing Base. This situation could in turn adversely affect the Partnership's ability to maintain or increase the level of its purchasing and marketing activities or otherwise adversely affect the Partnership's profitability and Available Cash (a full definition of Available Cash is set forth in the Partnership Agreement). 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 announced in December 2001 that it would not make a distribution for the fourth quarter of 2001 due to covenants in the Credit Agreement. Normally, that distribution would have been paid in February 2002. Under the terms of the Credit Agreement, the Partnership may not pay a distribution for any quarter unless the Borrowing Base exceeded the usage under the Credit Agreement (working capital plus outstanding letters of credit) for every day of the quarter by at least $20 million. For the first quarter of 2002, the Partnership will not pay a distribution as the excess of the Borrowing Base over the usage dropped below $20 million. Management of the Partnership does not anticipate that the Partnership will pay any distributions in 2002 and is unsure when distributions will resume. 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. 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, 2001.
43 Until December 2000, when the Partnership was restructured, GELP had an approximate 80.01% general partner interest in GCOLP. The remainder of GCOLP was held by Salomon, Howell and the General Partner. These interests are reflected in the consolidated financial statements as minority interests. 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" (FAS 121), 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. 12. Nonrecurring Charges In the fourth quarter of 2001, the Partnership recorded a charge of $1.5 million related to environmental matters including the Mississippi spill that occurred in 1999. This charge is reflected as a nonrecurring charge on the consolidated statement of operations for 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 a nonrecurring charge 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, ------------------------------ 2001 2000 1999 ------- -------- ------- Sales to affiliates $29,847 $ 35,095 $77,195 Purchases from affiliates $36,699 $130,679 $74,812 The related party sales in all years and the purchases in 2001 were made to Phibro, Inc., ("Phibro"), a subsidiary of Salomon. Purchases of $121.1 million and $67.9 million, respectively, were made in 2000 and 1999 from Phibro. These transactions were bulk and exchange transactions. Purchases of wellhead production were made from Howell in 2000 and 1999 of $9.6 million and $6.9 million, respectively. 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 $18,089,000, $16,946,000 and $16,687,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Credit Agreement In December 2001, Citicorp began providing the Partnership with a working capital and letter of credit facility. 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 will be amortized to earnings over the two-year life of the Credit Agreement and will be included in interest expense on the consolidated statements of operations.
44 Guaranty Fees In 2001, 2000 and 1999, Salomon provided a guaranty facility to the Partnership. For the years ended December 31, 2001, 2000 and 1999, the Partnership paid Salomon $1,250,000, $1,712,000 and $680,000, respectively, for guarantee fees. The guarantee fees are included as a component in cost of crude on the consolidated statements of operations. 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, 2001, 2000 and 1999 was $195,000, $241,000 and $152,000, respectively. Cash payments for interest were $1,391,000, $1,370,000 and $1,035,000 during the years ended December 31, 2001, 2000 and 1999, 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 at least 3% of each eligible employee's total compensation. The General Partner's costs relating to this plan were $603,000, $570,000 and $566,000 for the years ended December 31, 2001, 2000 and 1999, respectively. The General Partner also provided certain health care and survivor benefits for its active employees. In 2001, 2000 and 1999, these benefit programs were self-insured. The General Partner plans to continue self-insuring these plans in the future. The expenses of the General Partner for these benefits were $1,526,000, $1,718,000 and $1,067,000 in 2001, 2000 and 1999, 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
45 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. In 2001, 2000 and 1999, the Partnership recorded expense of $55,000, $1,192,000 and $1,459,000, 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. Market Risk 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. 18. 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. 19. 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.
46 At December 31, 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 are used in determining the fair value of the option contracts. If quoted prices are not available, fair values are 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. 20. 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. 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 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 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 fair value of the Partnership's net asset for derivatives had increased by $2.3 million for the year ended December 31, 2001, which is reported as a gain in the consolidated statement of operations under the caption "Change in fair value of derivatives". The consolidated balance sheet includes $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. 21. Commitments and Contingencies Leases The Partnership leases office space for its headquarters office under a long-term lease. The lease extends until December 31, 2005, although the lessor and the Partnership each have the option to terminate the lease at December 31, 2003. Should the Partnership terminate the lease at that date, it will owe a penalty of approximately $0.3 million. 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 four 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.
47 The future minimum rental payments under all noncancelable operating leases as of December 31, 2001, were as follows (in thousands). Tractors Office and Service Space Trailers Tanks Vehicles Total ------ ------- ------ -------- ------- 2002 $ 402 $ 2,865 $ 456 $ 266 $ 3,989 2003 413 2,865 465 264 4,007 2004 471 2,864 465 234 4,034 2005 392 2,413 - 83 2,888 2006 - 996 - 8 1,004 2007 and thereafter - 3,398 - - 3,398 ------ ------- ------ -------- ------- Total minimum lease obligations $1,678 $15,401 $1,386 $ 855 $19,320 ====== ======= ====== ======== ======= Total operating lease expense was as follows (in thousands). Year ended December 31, 2001 $ 4,379 Year ended December 31, 2000 $ 2,500 Year ended December 31, 1999 $ 1,674 The Partnership has contractual commitments (primarily forward contracts) arising in the ordinary course of business. At December 31, 2001, the Partnership had commitments to purchase 1,900,000 barrels of crude oil at fixed prices ranging from $17.50 to $20.20 per barrel extending to January 2002, and commitments to sell 1,900,000 barrels of crude oil at fixed prices ranging from $16.40 to $20.25 per barrel extending to January 2002. Additionally, the Partnership had commitments to purchase 4,608,000 barrels of crude oil extending to April 2004, and commitments to sell 4,530,000 barrels of crude oil extending to June 2002, both associated with market-price related contracts. 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 the duties of care and loyalty owed by the defendants to the purported class in connection with making a proposal for restructuring. Management of the General Partner believes that the complaint is without merit and intends to vigorously defend the action. Pennzoil Lawsuit The Partnership has been named one of the defendants in a complaint filed by Thomas Richard Brown on January 11, 2001, in the 125th District Court of Harris County, cause No. 2001-01176. Mr. Brown, an employee of Pennzoil-Quaker State Company ("PQS"), seeks damages for burns and other injuries suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. On January 17, 2001, PQS filed a Plea in Intervention in the cause filed by Mr. Brown. PQS seeks property damages, loss of use and business interruption. Both plaintiffs claim the fire and explosion was caused, in part, by Genesis selling to PQS crude oil that was contaminated with organic chlorides. Management of the Partnership believes that the suit is without merit and intends to vigorously defend itself in this matter. Management of the Partnership believes that any potential liability will 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.
48 The Partnership is subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance. As part of the formation of the Partnership, Salomon and Howell agreed to be responsible for certain environmental conditions related to their ownership and operation of their respective assets contributed to the Partnership and for any environmental liabilities which Basis or Howell may have assumed from prior owners of these assets. The Partnership's management has made an assessment of its potential environmental exposure, and primarily as a result of the spill from the Mississippi System, has recorded a charge of $1.5 million as a nonrecurring item in its consolidated statement of operations for the year ended December 31, 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.