10-K/A 1 0001.txt ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K/A X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ----- ACT OF 1934 For the fiscal year ended December 31, 1999 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 New York 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 New York Stock Exchange on March 1, 2000, was approximately $68 million. At March 31, 2000, 8,624,910 Common Units were outstanding. ================================================================================ 2 GENESIS ENERGY, L.P. 1999 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 20 Item 8. Financial Statements and Supplementary Data 20 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 21 Part III Item 10.Directors and Executive Officers of the Registrant 21 Item 11.Executive Compensation 23 Item 12.Security Ownership of Certain Beneficial Owners and Management 26 Item 13.Certain Relationships and Related Transactions 27 Part IV Item 14.Exhibits, Financial Statement Schedules and Reports on Form 8-K 28 3 PART I Item 1. Business General Genesis Energy, L.P., a Delaware limited partnership, was formed in December 1996. With the proceeds of an offering of common limited partnership units ("Common Units") to the public, Genesis Energy, L.P., through its affiliated limited partnership, Genesis Crude Oil, L.P., and its subsidiary partnerships (collectively the "Partnership" or "Genesis") acquired the crude oil gathering and marketing operations of Basis Petroleum, Inc. ("Basis") and the crude oil gathering, marketing and pipeline operations of Howell Corporation and its subsidiaries ("Howell"). The Partnership is an independent gatherer and marketer of crude oil. Genesis' operations are concentrated in Texas, Louisiana, Alabama, Florida, Mississippi, New Mexico, Kansas and Oklahoma. In its gathering and marketing business, Genesis is principally engaged in the purchase and aggregation of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities for resale at various points along the crude oil distribution chain, which extends from the wellhead to aggregation and terminal facilities, refineries and other end markets (the "Distribution Chain"). 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 76 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. In addition, as part of its gathering and marketing business, Genesis makes 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 exchanges crude oil with third parties through exchange or buy/sell agreements. In the fourth quarter of 1999, Genesis purchased an average of approximately 99,000 barrels per day of crude oil at the wellhead from approximately 9,600 leases. Genesis currently transports a total of approximately 91,000 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. In October 1998, Genesis acquired 200 additional miles of pipelines and gathering lines that have become part of its Texas System. This additional pipeline mileage extends from the West Columbia area in Texas to Webster, Texas. Approximately 2.0 million barrels of associated storage capacity is owned by Genesis. 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 was owned 54% by Salomon Smith Barney Holdings Inc. ("Salomon") and 46% by Howell. Effective February 28, 2000, Salomon acquired Howell's 46% interest in the General Partner. Salomon also owns 1,163,700 subordinated limited partner units in GCOLP, representing 10.58% of GCOLP. Howell owns 991,300 subordinated limited partner units in GCOLP, representing 9.01% of GCOLP. These subordinated limited partner interests are hereinafter referred to as Subordinated OLP Units. 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 or in bulk from major oil companies, intermediaries and other third parties. Genesis then transports the crude oil along the Distribution Chain for sale to or exchange with customers. 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. 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. 4 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 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. 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. 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 and gross margins are primarily a function of the level of throughput and storage activity. 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 the pipeline. Management Information and Risk Management Systems Genesis' computerized management information and risk management systems are integral to each stage of the gathering, transportation and marketing operations. Hand-held computer terminals combined with modems and satellite equipment are used by field personnel to provide data to Genesis' marketing personnel about crude oil purchases on a daily basis. Using this information from the field, management is able to monitor crude oil volumes, grades, locations and timing of delivery on a daily basis and to transmit instructions to field personnel regarding crude oil pick-up schedules and truck routing to crude oil injection stations and end markets. Using information transmitted from field personnel and representatives to its computers, Genesis has developed a database that includes volumes of crude oil purchases, volumes and prices under contracts with producers and customers, transportation costs and alternatives, and marketing and exchange opportunities. Genesis uses this database to support its management information and risk management systems. Risk management strategies, including those involving price hedges using NYMEX futures contracts, are important in creating and maintaining margins. Such hedging techniques require significant resources dedicated to managing forward positions and analyzing crude oil markets by grade and location so as to manage these differentials. By analyzing information in its database with internally developed software programs, Genesis is able to monitor crude oil volumes, grades, locations and delivery schedules and to coordinate marketing and exchange opportunities, as well as NYMEX hedging positions. This coordination enables the Partnership to net positions internally, thereby reducing NYMEX commissions, and further ensures that Genesis' NYMEX hedging activities are consistent with its business objectives. 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 580 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 1999, with its staff of division order specialists, Genesis distributed payments to approximately 24,000 interest owners. 5 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 connection with the purchase, sale or exchange of crude oil, subject to Genesis' compliance with specified terms and conditions, Salomon entered into a Master Credit Support Agreement to provide credit support until December 31, 2000, in the form of guarantees issued from time to time at the Partnership's request. In addition, the Partnership has a relationship with a bank to provide a working capital facility. See Note 9 of Notes to Consolidated Financial Statements. 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. Genesis has not experienced any nonpayments or nonperformance by its customers in 1999. 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 among all participants in the business 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 580 producers. In 1999, approximately 38% 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 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 December 31, 1999, approximately 260 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 is represented by labor unions, and the General Partner believes that the relationships with the employees are good. 6 Environmental Matters The Partnership is subject to federal and state laws and regulations relating to the protection of the environment. At the federal level such laws include, among others, the Clean Air Act, 42 U.S.C. Section 7401 et seq., as amended; the Clean Water Act, 33 U.S.C. Section 1251 et seq., as amended; the Resource Conservation and Recovery Act, 42 U.S.C. Section 6901 et seq., as amended; the Comprehensive Environmental Response, Compensation, and Liability Act, 42 U.S.C. Section 9601 et seq., as amended; and the National Environmental Policy Act, 42 U.S.C. Section 4321 et seq., as amended. 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 the Partnership will not incur such costs in material amounts. The Clean Air Act regulates, among other things, the emission of volatile organic compounds in order to minimize the creation of ozone. Such emissions may occur from the handling or storage of crude oil. The required levels of emission control are established in state air quality control implementation plans. Both federal and state laws impose substantial penalties for violation of these applicable requirements. The Clean Water Act controls, among other things, 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 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. 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 and maintenance activities 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 the Partnership's operations, substances may be generated or handled which fall within the definition of "hazardous substances." Under the National Environmental Policy Act ("NEPA"), a federal agency, in conjunction with a permittee, 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. The Partnership is subject to similar state and local environmental laws and regulations that may also address additional environmental considerations of particular concern to a state. As part of the partnership formation, Salomon and Howell are responsible for certain environmental conditions related to their ownership and operation of their respective assets transferred to the Partnership and for any environmental liabilities which Salomon or Howell may have assumed from prior owners of these assets. Neither Salomon nor Howell, however, will be required to indemnify the Partnership for any liabilities resulting from an invasive environmental site investigation unless such investigation was undertaken as a result of (i) certain requirements imposed by a lending institution, (ii) any governmental or judicial proceeding, (iii) any disposition of assets, (iv) a discovery in the ordinary course of business of materials, or a discovery in prudent and customary business practice of the possible presence of such materials, that require regulatory disclosure or (v) any 7 complaints by property owners or public groups. In addition, the Partnership has assumed responsibility for the first $25,000 per occurrence as to any environmental liability, up to an annual aggregate of $200,000 and a total maximum liability of $600,000. 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. The oil then flowed into the Leaf River. The Partnership responded to this incident immediately, deploying crews to evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill had been substantially cleaned up, with ongoing monitoring and reduced clean-up activity expected to continue for several more months. The Partnership believes that the oil spill is covered by insurance and the financial impact on the Partnership for the cost of the clean-up will not be 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. At this time, it is not possible to predict whether the Partnership will be fined, the amount of such fines or whether such governmental agencies will prevail in imposing such fines. See Note 18 of Notes to Consolidated Financial Statement. The segment of the Mississippi System where the spill occurred has been shut down and will not be restarted until regulators give their approval. Regulatory authorities may require specific testing or changes to the pipeline before allowing the Partnership to restart the system. At this time, it is unknown whether there will be any required testing or changes and the related cost of that testing or changes. 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, among other things, that to be lawful, petroleum pipeline rates be just and reasonable and not unduly discriminatory. The ICA permits 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. Howell is responsible for any ICA liabilities with respect to activities or conduct during periods prior to the closing of the Partnership's initial public offering of Common Units, and the Partnership is responsible for ICA liabilities with respect to activities or conduct thereafter. The Partnership adopted all of Howell's tariffs in effect on the date of the transfer of the assets to Genesis. None of the 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, the following: (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", limited 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 8 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 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. Because of the novelty and uncertainty surrounding the indexing methodology as well as numerous untested associated issues, the General Partner is unable to predict with certainty whether, how or the extent to which FERC may apply the methodologies to the Jay and Mississippi systems, which FERC regulates. The General Partner adopted Howell's preexisting tariffs and rates pertaining to the Jay and Mississippi Systems and intends to rely on the indexation procedures available under FERC regulations. Nevertheless, by protest, complaint or shipper challenge to the Partnership's grandfathered or indexed rates, the Partnership 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. Texas Intrastate Regulation The intrastate common carrier pipeline operations of the Partnership 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 the Partnership and has not investigated the rates or practices of such carriers in the absence of shipper complaints, which have been few and almost invariably settled informally. Given this history, although no assurance can be given that the tariffs to be charged by the Partnership would ultimately be upheld if challenged, the General Partner believes that the tariffs now in effect can be sustained. Howell is responsible for any liabilities under the applicable Texas statutes with respect to activities or conduct during periods prior to the closing, and the Partnership is responsible for such liabilities with respect to activities or conduct thereafter. The Partnership adopted the tariffs in effect on the date of the closing of the Partnership's initial public offering of Common Units. Pipeline Safety Regulation The Partnership'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. The Partnership has conducted hydrostatic testing of most segments. Significant expenses could be 9 incurred in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities. States are largely preempted from regulating pipeline safety by federal law but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. The Partnership does not anticipate any significant problems in complying with applicable state laws and regulations in those states in which it operates. The Partnership's crude oil pipelines are also subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The General Partner believes that the Partnership'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 the Partnership's expenditures in the future to comply with higher industry and regulatory safety standards such as those described above. Such expenditures cannot be accurately estimated at this time, although the General Partner does not expect that such expenditures will have a material adverse impact on the Partnership, except to the extent additional testing requirements or safety measures are imposed. Trucking regulation The Partnership operates its fleet of 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, keeping of 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. The Partnership is also subject to OSHA with respect to its trucking operations. Commodities regulation The Partnership'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 are 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 the Partnership believes that its expectations regarding future events are based on reasonable assumptions, it can give no assurance that its goals will be achieved or that its expectations regarding future developments will prove to be correct. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include changes in regulations, the Partnership's success in obtaining additional lease barrels, changes in crude oil production volumes (both world-wide as well as 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 Partnership's risk management activities, credit requirements by counterparties of the Partnership, the Partnership's ability to replace its Guaranty Facility from Salomon with a bank facility and replace its Working Capital Facility from Bank One with another facility, any requirements for testing or changes to the Mississippi System as a result of the December spill, the final determination of the causation of the December spill and the effects of that determination on insurance coverage, and conditions of the capital markets and equity markets during the periods covered by the forward looking 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 750-mile Texas system, the 117-mile Jay System extending between Florida and Alabama, and the 281-mile Mississippi System extending between Mississippi and Louisiana. The Partnership also owns approximately 2.0 million barrels of storage capacity associated with the pipelines. These storage capacities include approximately 200,000 barrels each on the Mississippi and Jay Systems and 1.4 million barrels on the Texas System, primarily at the Satsuma terminal in Houston, Texas. 10 In addition to transporting crude oil by pipeline, the Partnership transports crude oil through a fleet of owned and leased tractors and trailers. At December 31, 1999, the trucking fleet consisted of approximately 76 tractor- trailers. The trucking fleet generally hauls the crude oil to one of the approximately 127 pipeline injection stations owned or leased by the Partnership. 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, will not have a material adverse effect on the financial condition or results of operations of the Partnership. See Note 18 of Notes to Consolidated Financial Statements. Item 4. Submission of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders during the year ended December 31, 1999. 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, as reported on the New York Stock Exchange Composite Tape, and the amount of cash distributions paid per Common Unit.

Price Range Cash ----------------------- ------------- High Low Distributions --------- -------- --------------- 1999 ---- First Quarter $16.3125 $13.2500 $0.50 Second Quarter $15.2500 $13.7500 $0.50 Third Quarter $15.5000 $11.9375 $0.50 Fourth Quarter $12.8125 $ 6.6250 $0.50 1998 ---- First Quarter $20.3750 $16.6250 $0.50 Second Quarter $19.8750 $17.2500 $0.50 Third Quarter $18.0000 $13.6875 $0.50 Fourth Quarter $19.1250 $13.6250 $0.50 _____________________ Cash distributions are shown in the quarter paid and are based on the prior quarter's activities.

At December 31, 1999, there were 8,620,062 Common Units and 2,155,000 Subordinated OLP Units outstanding. As of December 31, 1999, there were approximately 12,000 record holders and beneficial owners (held in street name) of the Partnership's Common Units. There is no established public trading market for the Partnership's Subordinated OLP 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. Distributions of Available Cash to the Subordinated Unitholders will be subject to the prior rights of the Common Unitholders to receive the Minimum Quarterly Distribution ("MQD") for each quarter during the subordination period, which will not end earlier than December 31, 2001, and to receive any arrearages in the distribution of the MQD on the Common Units for prior quarters during the subordination period. In connection with the Partnership's initial public offering of Common Units in December 1996, Salomon and the Partnership entered into a Distribution Support Agreement pursuant to which, among other things, Salomon agreed that it would contribute up to $17.6 million to the Partnership in exchange for Additional Partnership Interests ("APIs"), if necessary, to support the Partnership's ability to pay the MQD on Common Units. Salomon's obligation to purchase APIs will end no later than December 31, 2001, with the actual termination subject to the levels of distributions that have been made prior to the termination date. At December 31, 1999, Salomon had provided $3.9 million of distribution support and provided $2.2 million additional distribution support in February 2000. After February 2000, $11.5 million remains of Salomon's distribution support commitment. 12 Item 6. Selected Financial Data (in thousands, except per unit and volume data) The table below includes selected financial data for the Partnership for the years ended December 31, 1999, 1998 and 1997 and one month ended December 31, 1996 and includes the results of operations acquired from Basis and Howell. Since Basis had the largest ownership interest in the Partnership, the net assets acquired from Basis were recorded at their historical carrying amounts and the crude oil gathering and marketing division of Basis was treated as the Predecessor and the acquirer of Howell's operations. The acquisition of Howell's operations was treated as a purchase for accounting purposes.

Eleven One Month Months Ended Ended Year Ended Year Ended December 31, December 31, November 30, December 31, ------------------------------------------- 1999 1998 1997 1996 1996 1996 1995 (Pro forma) (Predecessor)(Predecessor) (Unaudited) ---------- ---------- ---------- ---------- -------- ---------- ---------- Income Statement Data: Revenues: Gathering & marketing revenues $2,144,646 $2,216,942 $3,354,939 $4,565,834 $370,559 $3,598,107 $3,440,065 Pipeline revenues 16,366 16,533 17,989 16,780 1,426 - - ---------- ---------- ---------- ---------- -------- ---------- ---------- Total revenues 2,161,012 2,233,475 3,372,928 4,582,614 371,985 3,598,107 3,440,065 Cost of sales: Crude cost 2,118,318 2,184,529 3,331,184 4,526,363 366,723 3,573,086 3,409,759 Field operating costs 11,669 12,778 12,107 15,092 1,290 6,744 7,152 Pipeline operating costs 8,161 7,971 6,016 4,978 463 - - ---------- ---------- ---------- ---------- -------- ---------- ---------- Total cost of sales 2,138,148 2,205,278 3,349,307 4,546,433 368,476 3,579,830 3,416,911 ---------- ---------- ---------- ---------- -------- ---------- ---------- Gross margin 22,864 28,197 23,621 36,181 3,509 18,277 23,154 General and administrative expenses 11,649 11,468 8,557 9,470 1,363 3,316 3,658 Depreciation and amortization 8,220 7,719 6,300 6,834 518 1,396 4,815 Nonrecurring charge - 373 - - - - - ---------- ---------- ---------- ---------- -------- ---------- ---------- Operating income 2,995 8,637 8,764 19,877 1,628 13,565 14,681 Interest income (expense), net (929) 154 1,063 56 56 294 173 Other income (expense) 849 28 21 (74) - (83) (197) ---------- ---------- ---------- ---------- -------- ---------- ---------- Net income before minority interests 2,915 8,819 9,848 19,859 1,684 13,776 14,657 Minority interests 583 1,763 1,968 3,970 337 - - ---------- ---------- ---------- ---------- -------- ---------- ---------- Net income $ 2,332 $ 7,056 $ 7,880 $ 15,889 $ 1,347 $ 13,776 $ 14,657 ========== ========== ========== ========== ======== ========== ========== Net income per common unit-basic and diluted $ 0.27 $ 0.80 $ 0.90 $ 1.81 $ 0.15 N/A N/A ========== ========== ========== ========== ======== Balance Sheet Data (at end of period): Current assets $ 274,717 $ 185,216 $ 232,202 $ 410,371 $410,371 N/A $ 279,285 Total assets 380,592 297,173 331,114 509,900 509,900 N/A 283,036 Long-term liabilities 3,900 15,800 - - - N/A - Equity of parent - - - - - N/A (8,437) Minority interest 30,571 29,988 28,225 26,257 26,257 N/A - Partners' capital 53,585 67,871 78,351 85,080 85,080 N/A - Other Data: Maintenance capital expenditures $ 1,682 $ 1,509 $ 3,785 $ 2,535 $ 106 $ 1,100 $ 17 EBITDA $ 12,064 $ 16,384 $ 15,085 $ 26,637 $ 2,146 $ 14,878 $ 19,299 Volumes (bpd): Gathering and marketing: Wellhead 93,397 114,400 104,506 116,263 120,553 83,239 83,551 Bulk and exchange 242,992 325,468 346,760 463,054 380,354 417,939 439,060 Pipeline 94,048 85,594 89,117 86,557 85,874 - - -------------------------- The unaudited pro forma selected financial data of the Partnership includes (a) the historical operating results of the crude oil gathering and marketing operations of Basis, (b) the historical crude gathering, marketing and pipeline transportation operations of Howell and (c) certain pro forma adjustments to the historical results of operations of Basis and Howell as if the Partnership had been formed on January 1, 1996. Net income excludes the effect of income taxes for the Predecessor. The General Partner estimates that capital expenditures necessary to maintain the existing asset base at current operating levels will be $2 million each year. EBITDA (earnings before interest expense, income taxes, depreciation and amortization and minority interests) 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).

13 The table below summarizes the Partnership's quarterly financial data for 1999 and 1998 (in thousands, except per unit data). 1999 Quarters -------------------------------------- First Second Third Fourth -------- -------- -------- -------- Revenues $383,723 $513,388 $593,817 $670,084 Gross margin $ 5,769 $ 6,321 $ 5,461 $ 5,313 Operating income $ 698 $ 1,241 $ 667 $ 389 Net income $ 1,109 $ 804 $ 254 $ 165 Net income per Common Unit- basic and diluted $ 0.13 $ 0.09 $ 0.03 $ 0.02 1998 Quarters -------------------------------------- First Second Third Fourth -------- -------- -------- -------- Revenues $650,257 $561,813 $526,442 $494,963 Gross margin $ 6,336 $ 6,047 $ 8,432 $ 7,382 Operating income $ 1,962 $ 889 $ 3,365 $ 2,421 Net income $ 1,728 $ 811 $ 2,662 $ 1,855 Net income per Common Unit- basic and diluted $ 0.20 $ 0.09 $ 0.30 $ 0.21 Item 7. Management's Discussion and Analysis of Financial Condition and 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. Results of Operations Selected financial data for this discussion of the results of operations follows, in thousands. Years Ended December 31, -------------------------------- 1999 1998 1997 ---------- ---------- ---------- Revenues Gathering & marketing $2,144,646 $2,216,942 $3,354,939 Pipeline $ 16,366 $ 16,533 $ 17,989 Gross margin Gathering & marketing $ 14,659 $ 19,635 $ 11,648 Pipeline $ 8,205 $ 8,562 $ 11,973 General and administrative expenses $ 11,649 $ 11,468 $ 8,557 Depreciation and amortization $ 8,220 $ 7,719 $ 6,300 Operating income $ 2,995 $ 8,637 $ 8,764 Interest income (expense), net $ (929)$ 154 $ 1,063 Other income (expense) $ 849 $ 28 $ 21 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 equivalent amounts. Because period-to-period variations in revenues and cost of sales are not generally meaningful in analyzing the variation in gross margin for gathering and marketing operations, such changes are not addressed in the following discussion. In our gathering and marketing business, we seek to purchase and sell crude oil at points along the Distribution Chain where we can achieve positive gross margins. We generally purchase crude oil at prevailing 14 prices from producers at the wellhead under short-term contracts. We then transport the crude along the Distribution Chain for sale to or exchange with customers. In addition to purchasing crude at the wellhead, Genesis purchases crude oil in bulk at major pipeline terminal points and enters into exchange transactions with third parties. We generally enter into exchange transactions only when the cost of the exchange is less than the alternate cost we would incur in transporting or storing the crude oil. In addition, we often exchange one grade of crude oil for another to maximize our margins or meet our contract delivery requirements. These bulk and exchange transactions are characterized by large volumes and narrow profit margins on purchases and sales. Generally, as we purchase crude oil, we simultaneously establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation with respect to futures contracts on the New York Mercantile Exchange. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases, on the one hand, and sales or future delivery obligations, on the other hand. It is our policy not to hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes. 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, 1999 Compared with Year Ended December 31, 1998 Gross Margin. Gathering and marketing gross margins decreased $4.9 million or 25% to $14.7 million for the year ended December 31, 1999, as compared to $19.6 million for the year ended December 31, 1998. The decline in gross margin is primarily attributed to lower volumes purchased at the wellhead and in bulk at major trade locations. In 1999, the Partnership's average wellhead volumes declined approximately 21,000 barrels per day. Wellhead purchases fell from an average of 114,000 barrels per day in 1998 to 93,000 barrels per day in 1999. The decline in wellhead volumes began during the second half of 1998 in response to weakening crude oil prices. Volumes declined from 118,000 barrels per day during the first half of the year to 111,000 barrels per day during the second half of the year. A large contract with Pioneer Natural Resources expired at the end of 1998, reducing volumes at the beginning of 1999 by an additional 21,000 barrels per day. The loss of the Pioneer volumes and continued declines associated with low crude oil prices cut wellhead volume during the first half of 1999 to an average of 89,000 barrels per day. The Partnership increased wellhead volumes during the second half of 1999 primarily by obtaining existing production by paying higher prices for the production than the previous purchaser. Increased volumes obtained through competition based on price for existing production generally result in incrementally lower margins per barrel. Wellhead purchases increased to 92,000 barrels per day during the third quarter and to 99,000 barrels per day for the fourth quarter. The Partnership's lease business feeds into its marketing and exchange activities. The decline in wellhead volumes, as well as significant changes in price relationships for various grades, locations and timing of delivery of crude oil, resulted in lower bulk and exchange volumes in 1999. Bulk and exchange volumes declined 82,000 barrels per day, dropping from 325,000 barrels per day in 1998 to 243,000 barrels per day in 1999. Gathering and marketing gross margins in 1999 were positively impacted by a widening spread between the price of crude oil paid at the wellhead and the price of crude oil at the point of sale, as crude oil inventories declined and refinery demand for prompt supply improved. The Partnership also implemented changes in its operations in response to declining wellhead volumes. The changes implemented were a review of tractor and trailer utilization and realignment of the locations of equipment, allowing Genesis to sell excess equipment and reduce personnel and operating costs related to the vehicles. Field operating costs decreased in total by $1.1 million, with the reductions in the number of drivers and supervisory personnel decreasing payroll and benefits by $0.9 million. Disposals of excess tractors and trailers reduced fuel and repair costs by $0.2 million. Pipeline gross margin decreased $0.4 million or 4% to $8.2 million for the year ended December 31, 1999, as compared to $8.6 million for the year ended December 31, 1998. Although average daily volumes increased 10%, the average length of the pipeline movement was shorter, resulting in less tariff income. Pipeline operating costs increased due to increased expenditures for corrosion control of approximately $0.1 million and the 15 costs associated with the spill the Partnership had from its Mississippi System in December 1999 of approximately $0.1 million. General and administrative expenses. General and administrative expenses increased $0.2 million in 1999 over the 1998 level. This increase can be attributed to expenditures related to addressing the Year 2000 issue in 1999, totaling $0.4 million that were charged to general and administrative expenses. This increase in costs for the Year 2000 issue was partially offset by decreases of less than $0.1 million each in travel and entertainment expenses and expense related to the restricted unit plan due to employee resignations. Depreciation and amortization. In April 1998, the Partnership acquired the gathering and marketing assets of Falco S&D, Inc. ("Falco"). Twelve months of depreciation and amortization on these assets is included in 1999, while 1998 only included depreciation and amortization from the date of acquisition. The increase of $0.5 million in depreciation and amortization to $8.2 million for the year ended December 31, 1999, resulted primarily from this asset acquisition. Interest income (expense), net. In 1998, the Partnership had net interest income of $0.2 million. In 1999, the Partnership had net interest expense of $0.9 million. This difference of $1.1 million is attributable to increased borrowings by the Partnership in 1998 to acquire the Falco assets and to acquire a pipeline near West Columbia, Texas. As these acquisitions occurred, the Partnership had less available funds and increased its borrowings under its loan agreement. The borrowings were outstanding throughout 1999. Additionally, market interest rates, as evidenced by the prime rate, rose during 1999 by 0.75%, also increasing the Partnership's interest costs. Other income (expense). In 1999, the Partnership recognized a gain of $0.9 million as a result of the sale of excess tractors and trailers. Year Ended December 31, 1998 Compared with Year Ended December 31, 1997 Gross Margin. Gathering and marketing gross margins increased $7.9 million or 68% to $19.6 million for the year ended December 31, 1998, as compared to $11.7 million for the year ended December 31, 1997. The increase in gross margin can be attributed to the acquisition of the gathering and marketing assets of Falco in April 1998 and improvements in the relationships between various market prices during 1998, allowing the Partnership to apply its risk management techniques to forward purchases and sales opportunities to increase gross margin. By the end of 1998, price levels for crude oil had declined approximately 39% from prices at the beginning of 1998. While the decline in price levels, as previously stated, does not directly impact the Partnership's gross margins, the decline generally does reduce the quantities of crude oil available for purchase at the wellhead due to curtailed production and drilling activity. Through the acquisition of the gathering and marketing assets of Falco in April 1998, the Partnership was able to improve its average wellhead volumes over 1997 levels, although volumes in the fourth quarter had declined to an average of 107,758 barrels per day. Pipeline gross margin decreased $3.4 million or 28% to $8.6 million for the year ended December 31, 1998, as compared to $12.0 million for the year ended December 31, 1997. The Partnership experienced a decline in its daily throughput volumes of 8%, decreasing pipeline revenues by $1.5 million. In October 1998, the Partnership acquired 200 additional miles of pipeline in the West Columbia area of Texas. This addition resulted in a restoration of throughput volumes by the end of 1998 to levels at the beginning of the year. Throughput volumes on the existing pipelines declined in 1998 as oil producers reduced exploration and production volumes in areas serviced by the Partnership's pipelines. Also contributing to the decline in pipeline gross margins were higher operating costs in 1998. These higher costs can be attributed to lease payments beginning in the second quarter of 1998 on a new segment of pipeline of $0.5 million, repairs on the Main Pass pipeline prior to its shut-in of $0.2 million, and increased routine maintenance expenditures of $0.2 million. General and administrative expenses. In 1998, general and administrative expenses increased by $2.9 million or 34% to $11.5 million. This increase can be attributed primarily to three factors. First, the estimated total charge for the Restricted Unit Plan is being recognized over the three- year vesting period beginning in 1998. In 1998, that noncash charge was $1.6 million. Second, in 1998 the Partnership no longer benefited from the sharing of certain costs with Basis under the terms of a Corporate Services Agreement as it did in 1997. Third, costs increased due to the addition of marketing and administrative personnel by the Partnership in April 1998 as a result of the Falco asset acquisition. 16 Depreciation and amortization. Depreciation and amortization increased from $6.3 million in 1997 to $7.7 million in 1998, primarily attributable to depreciation and amortization on the assets acquired from Falco. Nonrecurring charge. In 1998, the Partnership recorded a non-recurring charge of $0.4 million as a result of the shut-in of its Main Pass pipeline located offshore. The charge consisted of $0.1 million of costs related to the shut-in and a $0.3 million write-down of the asset. Interest income (expense), net. Net interest income declined $0.8 million or 89% to $0.2 million for the year ended December 31, 1998 as compared to $1.0 million for the year ended December 31, 1997. As a result of the acquisition of the assets of Falco and the pipeline near West Columbia, Texas, in 1998, the Partnership had less cash available to temporarily invest. Interest expense increased as the Partnership borrowed funds under its loan agreement during the year. Hedging Activities Genesis routinely utilizes forward contracts, swaps, options and futures contracts in an effort to minimize the impact of market fluctuations on inventories and contractual commitments. Gains and losses on forward contracts, swaps and futures contracts used to hedge future contract purchases of unpriced crude oil, where firm commitments to sell are required prior to establishment of the purchase price, are deferred until the margin from the underlying risk element of the hedged item is recognized. The Partnership recognized net gains of $0.7 million, $1.4 million and $1.1 million for the years ended December 31, 1999, 1998 and 1997, respectively, related to its hedging activity. Liquidity and Capital Resources Cash Flows Net cash provided by operations was $10.1 million for the year ended December 31, 1999 as compared to $16.4 million for the year ended December 31, 1998. The decrease in cash flow in 1999 was due primarily to the reduction in the Partnership's gross margin. Net cash used in investing activities was $1.3 million and $17.5 million for the years ended December 31, 1999 and 1998, respectively. In 1999, the Partnership expended $2.7 million on property additions and received $1.0 million from the sale of excess trucking equipment. In 1998, the Partnership acquired the gathering and marketing assets of Falco, a pipeline near West Columbia, Texas, and other pipeline property additions. Net cash used in financing activities was $9.8 million and $3.0 million for the years ended December 31, 1999 and 1998, respectively. In 1999 and 1998, the Partnership paid distributions to the Common Unitholders and the General Partner totaling $17.6 million. In 1999, the Partnership received $3.9 million of Distribution Support from Salomon. The Partnership also paid $0.3 million and $1.2 million in 1999 and 1998, respectively, to acquire Common Units in the open market for treasury, some of which were subsequently reissued under the Restricted Unit Plan. Cash flows from financing activities were provided by borrowings in the amount of $4.1 million and $15.8 million under the loan agreement in 1999 and 1998, respectively. Capital Expenditures 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 million for various small projects. In 1998, the Partnership expended $16.2 million for capital expenditures for projects related to the expansion of its business activities and $1.5 million for maintenance capital expenditures. The expansion projects included the acquisition of the gathering and marketing assets of Falco, located primarily in Louisiana and East Texas and the acquisition of 200 miles of pipeline in the West Columbia area of Texas. This pipeline begins in Jackson County, Texas, and ends at Genesis' Webster Station in Harris County. In 1997, the Partnership made a one-time expenditure of $1.5 million for furnishings for new offices. Additionally, the Partnership expended $2.3 million for capital expenditures relating to its existing operations and $2.2 million for project additions. The principal project addition related to expenditures that enabled the Partnership to transport crude from a new area in Texas in its pipeline. The Partnership has no material commitments for capital expenditures for 2000. 17 Working Capital and Credit Resources Pursuant to the Master Credit Support Agreement, Salomon is providing credit support in the form of a Guaranty Facility in connection with the purchase, sale or exchange of crude oil in the ordinary course of the Partnership's business with third parties. The aggregate amount of the Guaranty Facility will be limited to $300 million for the year ending December 31, 2000 (to be reduced in each case by the amount of any obligation to a third party to the extent that such party has a prior security interest in the collateral under the Master Credit Support Agreement). The Partnership is required to pay a guaranty fee to Salomon which will increase over the remaining year, thereby increasing the cost of the credit support provided to the Partnership under the Guaranty Facility. During 1999, the guaranty fee was 0.50% of the amount of the guaranty utilization. In 2000, the fee will be 0.50% for the first half of the year and 0.75% for the remainder of the year. The Partnership will pay an additional fee of 1% on any guaranty utilization in excess of the $300 million commitment. The Partnership paid no fees for excess utilization in any period presented. Guaranty fees paid for the years ended December 31, 1999, 1998 and 1997 were $0.7 million, $0.6 million and $0.7 million, respectively. At December 31, 1999, the aggregate amount of obligations covered by guarantees was $164 million, including $72 million in payable obligations and $92 million in estimated crude oil purchase obligations for January 2000. Salomon received a security interest in all the Partnership's receivables, inventories, general intangibles and cash to secure obligations under the Master Credit Support Agreement. Salomon provided a Working Capital Facility to the Partnership until August 1998. At that time, the Working Capital Facility was replaced with a revolving credit/loan agreement ("Loan Agreement") with Bank One, Texas, N.A. ("Bank One"). The Loan Agreement provides for loans or letters of credit in the aggregate not to exceed the greater of $35 million or the Borrowing Base (as defined in the Loan Agreement). Loans will bear interest at a rate chosen by GCOLP which would be one or more of the following: (a) a Floating Base Rate (as defined in the Loan Agreement) that is generally the prevailing prime rate less one percent; (b) a rate based on the Federal Funds Rate plus one and one-half percent or (c) a rate based on LIBOR plus one and one-quarter percent. The Loan Agreement provides for a revolving period until August 14, 2000, during which time interest will be paid monthly. All loans outstanding on August 14, 2000, are due at that time. The Loan Agreement is collateralized by the accounts receivable and inventory of GCOLP, subject to the terms of an Intercreditor Agreement between Bank One and Salomon. There is no compensating balance requirement under the Loan Agreement. A commitment fee of 0.35% on the available portion of the commitment is provided for in the agreement. Material covenants and restrictions include requirements to maintain a ratio of current assets (as defined in the Loan Agreement) to current liabilities of at least 1:1 and to maintain tangible net worth in GCOLP, as defined in the Loan Agreement, of $65 million. The Partnership was in compliance with the covenants of the Loan Agreement at December 31, 1999. At December 31, 1999, the Partnership had $19.9 million of loans outstanding under the Loan Agreement. The Partnership had no letters of credit outstanding at December 31, 1999. At December 31, 1999, $15.1 million was available to be borrowed under the Loan Agreement. Management of the Partnership has entered into discussions with a bank regarding replacement of the Bank One Loan Agreement with a long-term facility. Based upon these discussions, management expects that it will be able to replace the Loan Agreement with a long-term facility subject to similar terms. If the Partnership is unable to complete the replacement agreement noted above, then other options will be pursued, some of which may have terms not as favorable to the Partnership, including increasing costs and pledging additional collateral. None of the Partnership's property is pledged as collateral for any obligations. The Partnership could also consider selling one of its pipeline systems, utilizing the proceeds to retire the Loan Agreement. While management believes that it will be able to replace the Loan Agreement on a long-term basis prior to its maturity, there can be no assurance that it will be able to do so. A failure to replace the Loan Agreement could result in the Partnership taking actions such as selling assets, limiting distributions and reducing its level of purchasing and marketing activities in future periods. There can be no assurance of the availability or the terms of credit for the Partnership. At this time, Salomon does not intend to provide guarantees or other credit support after the credit support period expires in December 2000. In addition, if the General Partner is removed without its consent, Salomon's credit support obligations will terminate. Further, Salomon's obligations under the Master Credit Support Agreement may be transferred or terminated early subject to certain conditions. Management of the Partnership intends to replace the 18 Guaranty Facility with a letter of credit facility with one or more third party lenders prior to December 2000 and has had preliminary discussions with banks about a replacement letter of credit facility. The General Partner may be required to reduce or restrict the Partnership's gathering and marketing activities because of limitations on its ability to obtain credit support and financing for its working capital needs. The General Partner expects that the overall cost of a replacement facility may be substantially greater than what the Partnership is incurring under its existing Master Credit Support Agreement. 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 or other financial support, make it more difficult for the Partnership to obtain such letters of credit, and/or may increase the cost of obtaining them. 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. At December 31, 1999, the Partnership's consolidated balance sheet reflected a working capital deficit of $17.8 million. This working capital deficit combined with the short-term nature of both the Guaranty Facility with Salomon and the Loan Agreement with Bank One could have a negative impact on the Partnership. Some counterparties use the balance sheet and the nature of available credit support as a basis for determining the level of credit support demanded from the Partnership as a condition of doing business. Increased demands for credit support beyond the maximum credit limitations and higher credit costs may 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 for distributions. 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.) Distributions of Available Cash to the holders of Subordinated OLP Units are subject to the prior rights of holders of Common Units to receive the minimum quarterly distribution ("MQD") for each quarter during the subordination period (which will not end earlier than December 31, 2001) and to receive any arrearages in the distribution of the MQD on the Common Units for prior quarters during the subordination period. MQD is $0.50 per unit. Salomon has committed, subject to certain limitations, to provide total cash distribution support, with respect to quarters ending on or before December 31, 2001, in an amount up to an aggregate of $17.6 million in exchange for Additional Partnership Interests ("APIs"). Salomon's obligation to purchase APIs will end no later than December 31, 2001, with the actual termination subject to the levels of distributions that have been made prior to the termination date. In 1999, the Partnership utilized $3.9 million of the distribution support from Salomon. An additional $2.2 million of distribution support was utilized in February 2000. After the distribution in February 2000, $6.1 million of distribution support has been utilized, and $11.5 million remains available through December 31, 2001 or until such amount is fully utilized, whichever comes first. Based on current market conditions, management of the General Partner expects to continue using distribution support at levels similar to recent support requirements. Management expects that distribution support will be fully utilized before its expiration at the end of 2001. Any APIs purchased by Salomon are not entitled to cash distributions or voting rights. The APIs will be redeemed if and to the extent that Available Cash for any future quarter exceeds an amount necessary to distribute the MQD on all Common Units and Subordinated OLP Units and to eliminate any arrearages in the MQD on Common Units for prior periods. In 1999 and 1998, the Partnership paid total distributions of $2.00 per unit to the Common Unitholders and the General Partner. This amount represented distributions for the period from October 1, 1997 to September 31, 1999. A distribution of $0.50 per unit, applicable to the fourth quarter of 1999, was paid on February 14, 2000 to holders of record on January 30, 2000. In 1997, the Partnership paid total distributions of $1.66 per unit, representing distributions for the period from the Partnership's inception in December 1996 through September 30, 1997. 19 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. The oil then flowed into the Leaf River. The Partnership responded to this incident immediately, deploying crews to evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill had been substantially cleaned up, with ongoing maintenance and reduced clean-up activity expected to occur for several more months. The estimated cost of the spill clean-up is expected to be $17 million. A final determination as to the cause of the spill has not been completed. The incident was reported to insurers, and incurred costs related to the clean-up efforts have been reimbursed or approved for reimbursement by the insurers. The insurers, however, have reserved the right to claim the return of the insurance proceeds should the final determination of cause be a cause not covered by the insurance policies. Based on its review of the policies and its understanding of the facts associated with the spill, management of the General Partner believes that the costs of the spill are covered by insurance and collection of the receivable is probable. In its 1999 financial statements, the Partnership charged to expense the deductible of $50,000 and recorded a liability for $17 million, which includes estimates for clean-up costs, ongoing maintenance related to the clean-up and settlement of claims of potential liabilities to landowners in connection with the spill. The Partnership recorded a receivable from the insurance company for the insurance proceeds. Should the ultimate determination of the cause of the spill prove not to be covered by insurance, the Partnership will be required to write off the receivable of $17 million. As a result of this crude oil spill, certain federal and state regulatory agencies may impose fines and penalties that would not be reimbursed by insurance. At this time, it is not possible to predict whether the Partnership will be fined, the amounts of such fines, or whether such governmental agencies would prevail in imposing such fines. The segment of the Mississippi System where the spill occurred has been temporarily shut down and will not be returned to service until regulators give their approval. Regulatory authorities may require specific testing or changes to the pipeline before allowing the Partnership to restart that segment of the system. At this time, it is unknown whether there will be any required testing or changes and the related cost of that testing or changes. If the costs of testing or changes are too high, that segment of the system may not be restarted. If this part of the Mississippi System is taken out of service, annual tariff revenues would be reduced by approximately $0.6 million and the net book value of that portion of the pipeline would be written down to its net realizable value, resulting in a non-cash write-off of approximately $6.0 million. Current Business Conditions A significant factor contributing to lower 1999 gross margins was the decline in domestic crude oil production caused by weakening oil prices. Despite significant increases in crude oil prices since the first quarter of 1999, U.S. onshore crude oil production volumes have not improved. Further, management of the General Partner has not seen significant improvement in the drilling and workover rig counts that would indicate that producers are expending capital to increase production. The first sign of recovery is normally an increase in the number of workover rigs, the rigs used for jobs that increase production from existing wells. In 1998, the monthly average number of workover rigs operating in the Partnership's primary operating areas was 653 rigs. That count dropped to 497 in 1999. Similarly, the average number of rotary rigs being utilized in the Partnership's primary operating areas to find or develop oil or natural gas declined from 386 rigs in 1998 to 275 rigs in 1999. Management of the General Partner believes that producers that survived the price downturn in 1998 and early 1999 by borrowing from banks or utilizing cash reserves are using the increased cash flow from higher prices to repay debt and replenish cash. Although there has been some increase in the number of drilling and workover rigs being utilized in the Partnership's primary operating areas during the early part of 2000, management of the General Partner expects that this increased activity is more likely to have the effect of reducing natural production declines rather than significantly increasing wellhead volumes in its operating areas. The Partnership's improved volumes during 1999 were due primarily to obtaining existing production by paying higher prices for the production than the previous purchaser. Increased volumes obtained through competition based on price for existing production generally result in incrementally lower margins per barrel. 20 The Partnership does not expect to experience meaningful improvements to gross margins in our existing business unless the energy industry takes action to cause significant improvements in domestic production levels. However, the Partnership intends to continue its strategy of increasing volumes purchased through competition unless significant improvements in domestic production levels occur. As crude oil prices rise, the Partnership's utilization of, and cost of credit under, the Guaranty Facility increases with respect to the same volume of business. The General Partner may be required to reduce or restrict the Partnership's gathering and marketing activities due to the $300 million limit of the Guaranty Facility. The cost of operating the Partnership's trucking fleet also rises as fuel costs rise. Additionally, as prices rise, the Partnership may have to increase the amount of its Loan Agreement in order to have funds available to meet margin calls on the NYMEX and to fund inventory purchases. No assurances can be made that the Partnership would be able to increase the size of its Loan Agreement or that changes to the terms of such increased Loan Agreement would not have a material impact on the results of operations or cash flows of the Partnership. 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 effects on future contractual commitments. The Partnership utilizes New York Mercantile Exchange ("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, 1999, the Partnership used futures, forward and options contracts exclusively in its hedging program with the latest contract being settled in January 2001. 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) 17 Carrying value $ 424 Fair value $ 424 Commodity Futures Contracts: Contract volumes (1,000 bbls) 12,665 13,132 Weighted average price per bbl $ 23.26 $ 22.75 Contract value (in thousands) $294,617 $298,715 Fair value (in thousands) $313,937 $316,640 Commodity Forward Contracts: Contract volumes (1,000 bbls) 4,830 4,090 Weighted average price per bbl $ 25.50 $ 24.81 Contract value (in thousands) $123,173 $101,492 Fair value (in thousands) $122,500 $102,555 Commodity Option Contracts: Contract volumes (1,000 bbls) 1,960 Weighted average strike price per bbl $ 3.15 Contract value (in thousands) $ 363 Fair value (in thousands) $ 390 The table above presents notional amounts in barrels, the weighted average contract price, total contract amount in U.S. dollars and total fair value amount in U.S. dollars. Fair values were determined by using the notional amount in barrels multiplied by the December 31, 1999 closing prices of the applicable NYMEX futures contract adjusted for location and grade differentials, as necessary. 21 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 Error! Bookmark not defined.. 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 Partnership's procedures for internal auditing and 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 directors of the General Partner are elected annually by the General Partner. All executive officers serve at the discretion of the General Partner. Name Age Position ------------------ -- ------------------------------------ A. Richard Janiak 53 Director and Chairman of the Board Mark J. Gorman 46 Director, Chief Executive Officer and President John P. vonBerg 46 Director, Vice Chairman of the Board, and Executive Vice President, Trading and Price Risk Management Michael A. Peak 46 Director Robert T. Moffett 48 Director Herbert I. Goodman 77 Director J. Conley Stone 68 Director John M. Fetzer 46 Executive Vice President Ross A. Benavides 46 Chief Financial Officer, General Counsel and Secretary Ben F. Runnels 59 Vice President, Trucking Operations Kerry W. Mazoch 53 Vice President, Crude Oil Acquisitions 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. Prior to joining Howell, Mr. Gorman worked for Marathon Oil Company ("Marathon") for fifteen years in various capacities in Crude Oil Acquisition and Finance and Administration, including Manager of Crude Oil Purchases and Sales and Manager of Crude Oil Trading and Risk Management. John P. vonBerg has served as a Director of the General Partner since December 1996 and as Vice Chairman of the Board and Executive Vice President, Trading and Price Risk Management, since October 1999. From December 1996 to October 1999, he served as President and Chief Executive Officer of the General Partner. He was Vice President of Crude Oil Gathering, Domestic Supply and Trading, for Basis and its predecessor, Phibro 22 USA, from January 1994 to December 1996. He managed the Gathering and Domestic Trading and Commercial Support functions for Phibro USA during 1993. Prior to 1993, Mr. vonBerg worked for Marathon for 13 years in various capacities, including Product Trading, Risk Management, Crude Oil Purchases and Sales, Finance, Auditing and Operations. Michael A. Peak was elected to the Board of Directors of the General Partner in April 1997. Since 1989, Mr. Peak has been a crude oil trader with Phibro, Inc., a wholly-owned subsidiary of Salomon Smith Barney Holdings Inc. Prior to joining Phibro, Inc., Mr. Peak worked for Marathon for thirteen years in various capacities, including Manager of Crude Oil Trading, Business Development for the Gulf Coast Pipeline Division, Controller of the Gulf Coast Pipeline Division, Natural Gas Liquids Trader and several planning positions. 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. From 1987 to 1992, Mr. Moffett was a partner in Moffett and Brewster, an oil and gas investment firm. 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. From 1988 until 1996 he was Chairman and Chief Executive Officer of Applied Trading Systems, Inc., a trading and consulting business. Prior to 1988, Mr. Goodman was with Gulf Trading and Transportation Company and Gulf Oil Corporation. 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. From 1976 to 1987, Mr. Stone served in a variety of executive positions with Exxon Pipeline Company. John M. Fetzer has served as Executive Vice President since October 1999. He was Senior Vice President, Crude Oil, for the General Partner since December 1996. He served in the same capacity for Howell Crude Oil Company from September 1994 to December 1996. From 1993 to September 1994, Mr. Fetzer was a private investor and a consultant and expert witness in oil and gas related matters. He held the positions of Senior Vice President, Marketing, from 1991 to 1993 and Vice President of Crude Oil Trading from 1986 to 1991 at Enron Oil Trading and Transportation. From 1981 to 1986, Mr. Fetzer served as Manager, Crude Oil Trading for UPG Falco and P&O Falco, which later became Enron Oil Trading and Transportation. Prior to joining P&O Falco he held various financial and commercial positions with Marathon, which he joined in 1976. 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 from June 1996 to May 1997 and Tax Director of Basis from May 1994 to May 1996. From March 1990 to April 1994, he served as Tax Manager for Lyondell. 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. Prior to that, he was Manager, Operations for JM Petroleum Corporation for four years. From 1974 until 1988, he was employed by Tesoro Petroleum Corp. and held the positions of Terminal Manager, Regional Manager, Pipeline Manager, and Division Manager, respectively. From 1962 until 1974, Mr. Runnels held various managerial positions at Ryder Tank Lines, Coastal Tank Lines, Robertson Tank Lines and Gulf Oil Corporation. Kerry W. Mazoch has served as Vice President, Crude Oil Acquisitions, of the General Partner since August 1997. From 1991 to 1997 he held the position of Vice President and General Manager of Crude Oil Acquisitions at Northridge Energy Marketing Corp., a wholly-owned subsidiary of TransCanada Pipelines Limited. From 1972 until 1991 he was employed by Mesa Pipe Line Company and held the positions of Vice President, Crude Oil, and General Manager, Refined Products Marketing. Prior to 1972, Mr. Mazoch worked for Exxon Company U.S.A. in various refined products marketing capacities. 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 23 no Forms 5 were required for those persons, the General Partner believes that during 1999 its officers and directors complied with all applicable filing requirements in a timely manner. Representatives of Salomon and Howell 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 1999, 1998 and 1997 to the Chief Executive Officer and each of Genesis' four other most highly compensated executive officers (the "Named Officers").

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 $ $ $ $ $ --------------------------- ---- ------------ ------ ------------ ---------------- ------------ Mark J. Gorman 1999 236,000 - - - 9,600 Chief Executive Officer 1998 230,000 37,500 - 570,891 9,600 and President 1997 212,500 37,500 - - 9,550 John P. vonBerg 1999 410,000 - - - 9,600 Executive Vice President, 1998 350,000 - - 570,891 9,600 Trading and Price Risk 1997 350,000 50,000 - - 9,550 Management John M. Fetzer 1999 211,000 - - - 9,600 Executive Vice President 1998 200,000 37,500 - 570,891 9,600 1997 200,000 37,500 - - 9,550 Kerry W. Mazoch 1999 166,000 - - - 9,600 Vice President, Crude 1998 166,000 25,000 - 231,057 4,800 Oil Acquisitions 1997 62,250 15,000 - - 1,743 Ross A. Benavides 1999 150,000 - - - 9,586 Chief Financial Officer, 1998 31,700 10,000 - 185,000 1,904 General Counsel and Secretary 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. Annual salary for the year 2000 is $270,000. Includes $4,800 of Company-matching contributions to a defined contribution plan and $4,800 of profit-sharing contributions to a defined contribution plan. Includes $4,793 of Company-matching contributions to a defined contribution plan and $4,793 of profit-sharing contributions to a defined contribution plan. Restricted units were awarded to the Named Officer on January 27, 1998. Under the terms of the Amended and Restated Restricted Unit Plan, the award will vest in increments of one-third annually 24 beginning on December 8, 1998. The vested units cannot be sold until one year after vesting. Prior to vesting, distributions will be paid on restricted units any time distributions are paid on the Subordinated OLP Units. After vesting, the Named Officer will receive distributions whenever distributions are paid to the Common Unitholders. Mr. Gorman received an award of 29,090 restricted units. At December 31, 1999, Mr. Gorman had 6,842 vested restricted units and 6,841 vested units for which the restriction period had expired. These units had a combined value of $110,319 (determined using closing market price of unrestricted units on December 31, 1999). He had 9,697 unvested restricted units with a value of $78,182. Mr. Gorman relinquished 2,855 of the units that vested in 1999 and 1998, respectively, so that the value of the units on the vesting date ($6.6875 and $16.8125 per unit, respectively) could be used to pay federal income taxes owed on the vested portion of the award. Mr. vonBerg received an award of 29,090 restricted units. At December 31, 1999, Mr. vonBerg had 5,717 vested restricted units and 6,841 vested units for which the restriction period had expired. These units had a combined value of $101,249 (determined using closing market price of unrestricted units on December 31, 1999). He had 9,697 unvested restricted units with a value of $78,182. Mr. vonBerg relinquished 3,980 and 2,855 of the units that vested in 1999 and 1998, respectively, so that the value of the units on the vesting date ($6.6875 and $16.8125 per unit, respectively) could be used to pay federal income taxes owed on the vested portion of the award. Mr. Fetzer received an award of 29,090 restricted units. At December 31, 1999, Mr. Fetzer had 6,842 vested restricted units and 6,841 vested units for which the restriction period had expired. These units had a combined value of $110,319155,550 (determined using closing market price of unrestricted units on December 31, 1999). He had 9,697 unvested restricted units with a value of $78,182. Mr. Fetzer relinquished 2,855 of the units that vested in 1999 and 1998 so that the value of the units on the vesting date ($6.6875 and $16.8125 per unit, respectively) could be used to pay federal income taxes owed on the vested portion of the award. Mr. Mazoch received an award of 12,121 restricted units. At December 31, 1999, Mr. Mazoch had 2,851 vested restricted units and 2,851 vested units for which the restriction period had expired. These units had a combined value of $45,972 (determined using closing market price of unrestricted units on December 31, 1999). He had 4,041 unvested restricted units with a value of $32,581. Mr. Mazoch relinquished 1,189 of the units that vested in 1999 and 1998 so that the value of the units on the vesting date ($6.6875 and $16.8125 per unit, respectively) could be used to pay federal income taxes owed on the vested portion of the award. Includes $4,800 of profit-sharing contributions to a defined contribution plan. Mr. Benavides received an award of 10,000 restricted units on October 27, 1998. Under the terms of the Amended and Restated Restricted Unit Plan, the award will vest in increments of one-third annually beginning on December 8, 1999. The vested units cannot be sold until one year after vesting. Prior to vesting, distributions will be paid on restricted units any time distributions are paid on the Subordinated OLP Units. After vesting, and Named Officer will receive distributions whenever distributions are paid to the Common Unitholders. At December 31, 1999, Mr. Benavides had 1,965 vested restricted units with a value of $15,843 (determined using closing market price of unrestricted units on December 31, 1999). He had 6,667 unvested restricted units with a value of $53,753. Mr. Benavides relinquished 1,368 of the units that vested in 1999 so that the value of the units on the vesting date ($6.6875 per unit) could be used to pay federal income taxes owed on the vested portion of the award. Includes $952 of Company matching contributions to a defined contribution plan and $952 of profit-sharing contributions to a defined contribution plan. Includes $4,750 of Company-matching contributions to a defined contribution plan and $4,800 of profit-sharing contributions to a defined contribution plan. Includes $1,743 of profit-sharing contributions to a defined contribution plan. Employment and Severance Agreements At formation, the General Partner entered into employment agreements with the following executive officers: Mr. vonBerg, Mr. Gorman, Mr. Fetzer and Mr. Runnels. When Mr. Benavides was employed, the General 25 Partner entered into an employment agreement with him. The agreements with Mr. Gorman, Mr. vonBerg and Mr. Fetzer expired December 31, 1999 and were replaced with severance agreements. The initial agreement with Mr. Runnels expired December 31, 1999; however, the General Partner exercised its option to extend the agreement for an additional two years. The agreement with Mr. Benavides expires in October 2000. The agreement with Mr. Runnels has five additional optional extension terms of one year each ("Extension Terms"). The agreements with Mr. Runnels and Mr. Benavides include 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 agreements 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. vonBerg and Mr. Fetzer 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 $270,000 for Mr. Gorman and Mr. Fetzer and $420,000 for Mr. vonBerg, (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. These provisions also apply to an involuntary termination of the executive (other than a termination for cause, as defined in the agreements). The severance agreements terminate on December 31, 2000, provided, however, that the benefits under the severance agreements apply through July 1, 2001. 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 240,000 Common Units (the "Restricted Units") have been allocated to approximately 32 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 vest annually beginning in December 1998. The remaining rights to receive 51,000 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. The participant shall receive cash awards based on the number of non-vested units held by such participant to the extent that distributions are paid on Subordinated OLP Units. To date, no distributions have been paid with respect to Subordinated OLP 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. 26 Incentive Plan In January 1997, the General Partner adopted the Genesis Incentive Compensation Plan (the "Incentive Plan") and amended it in January 1998. The Incentive Plan is designed to enhance the financial performance of the Partnership by rewarding the executive officers and other specific key employees for achieving annual financial performance objectives. The Incentive Plan will be administered by the Compensation Committee. Individual participants and payments, if any, for each calendar year will be determined by and in the discretion of the Compensation Committee. No incentive payments will be made with respect to any year unless (i) the aggregate MQD in the Incentive Plan year has been distributed to each holder of Common Units, plus any arrearage thereon, (ii) the Adjusted Operating Surplus generated during such year has equaled or exceeded the sum of the MQD on all of the outstanding Common Units and the related distribution on the General Partner's interest during such year and (iii) no APIs are outstanding. In addition, incentive payments will not exceed $375,000 with respect to any year unless (i) each holder of Subordinated OLP Units has also received the aggregate MQD and (ii) the Adjusted Operating Surplus generated during such year exceeded the sum of the MQD on all of the outstanding Common Units and Subordinated OLP Units and the related distribution on the General Partner's interest during such year. Any incentive payments will be at the discretion of the Compensation Committee, and the General Partner will be able to amend or change the Incentive 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 29, 2000.

Amount and Nature Name and Address of Beneficial Ownership Percent Title of Class of Beneficial Owner as of January 1, 2000 of Class ------------------------ ---------------------- ----------------------- -------- General Partner Interest Genesis Energy, L.L.C. 1 100.00 500 Dallas, Suite 2500 Houston, TX 77002 General Partner Interest Salomon Smith Barney Holdings Inc. 1 100.00 Seven World Trade Center New York, NY 10048 _____________________ 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.

The following table sets forth certain information as of February 29, 2000, 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. 27

Amount and Nature of Beneficial Ownership ------------------------------------------- Sole Voting and Shared Voting and Percent Title of Class Name Investment Power Investment Power of Class -------------------- ------------------ ---------------- ----------------- -------- Genesis Energy, L.P. A. Richard Janiak - - - Common Unit Mark J. Gorman 18,683 - * John P. vonBerg 18,558 - * Michael A. Peak 25,420 - * Robert T. Moffett - - - Herbert I. Goodman 2,000 - * J. Conley Stone 1,000 - * John M. Fetzer 18,683 - * Kerry W. Mazoch 5,702 - * Ross A. Benavides 4,965 - * All directors and executive officers as a group (11 in number) 100,073 - 1 _____________________ * Less than 1%

The above table includes shares owned by certain members of the families of the directors or executive officers, including shares in which pecuniary interest may be disclaimed. Item 13. Certain Relationships and Related Transactions Salomon and Howell own 1,163,700 and 991,300 Subordinated OLP Units, respectively, representing a 10.58% and 9.01% limited partner interest in GCOLP. 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, Howell and its subsidiaries and the General Partner in the ordinary course of its operations. During 1999, these transactions included: * Sales and purchases of crude oil from a subsidiary of Salomon totaling $77.2 million and $67.9 million, respectively. * Purchases of crude oil from a subsidiary of Howell totaling $6.9 million. * 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 $16.7 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 $0.7 million. Redemption and Registration Rights Agreement. Pursuant to the Redemption and Registration Rights Agreement, the Partnership has agreed, at the end of the Subordination Period or upon earlier conversion of Subordinated OLP Units into Common OLP Units, to use reasonable efforts to sell that number of Common Units equal to the number of Common OLP Units that Salomon or Howell is requesting be redeemed. The proceeds, net of underwriting discount or placement fees, if any, from such sale will be used by the Operating Partnership to redeem such Common OLP Units. The Partnership is obligated to pay the expenses incidental to redemption requests, other than the underwriting discount or placement fees, if any. The General Partner will have a proportionate percentage of its general partner interest in the Operating Partnership redeemed when Common OLP Units are redeemed in connection with the exercise of the redemption right. Distribution Support Agreement. To further enhance the Partnership's ability to distribute the Minimum Quarterly Distribution on the Common Units with respect to each quarter through the quarter ending December 31, 2001, Salomon has agreed in the Distribution Support Agreement, subject to certain limitations, to contribute or cause to be contributed cash, if necessary, to the Partnership in return for APIs. Salomon's obligation to purchase APIs is limited to a maximum amount outstanding at any one time equal to $17.6 million. As of December 31, 28 1999, $3.9 million of the Distribution Support had been utilized and an additional $2.2 million was utilized in February 2000. $11.5 million remains available for periods after February 2000. The Unitholders have no independent right separate and apart from the Partnership to enforce obligations of Salomon under the Distribution Support Agreement. 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 Error! Bookmark not defined.. (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 Agreement of Limited Partnership of Genesis ** 3.3 Certificate of Limited Partnership of Genesis Crude Oil, L.P. (the "Operating Partnership") 3.4 Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 3.4 to Registration Statement, File No. 333-11545) ** 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 Distribution Support Agreement among the Operating Partnership and Salomon Inc ** 10.4 Master Credit Support Agreement among the Operating Partnership, Salomon Inc and Basis ** 10.5 Redemption and Registration Rights Agreement among Basis, Howell, certain Howell subsidiaries, Genesis and the Operating Partnership 10.7 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) 10.8 Severance Agreement between Genesis Energy, L.L.C. and John P. vonBerg (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarterly period ended September 30, 1999) 10.9 Severance Agreement between Genesis Energy, L.L.C. and Mark J. Gorman (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarterly period ended September 30, 1999) 10.10 Severance Agreement between Genesis Energy, L.L.C. and John M. Fetzer (incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarterly period ended September 30, 1999) 10.11 Employment Agreement between Genesis Energy, L.L.C. and Ross A. Benavides (incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarterly period ended September 30, 1998) ** 10.12 Employment Agreement between Genesis Energy, L.L.C. and Ben F. Runnels 10.13 Extension of Employment Agreement between Genesis Energy, L.L.C. and Ben F. Runnels, (incorporated by reference to Exhibit 10.6 to Form 10-Q for the quarterly period ended September 30, 1999) 10.14 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) 10.15 Third Amendment to Master Credit Support Agreement (incorporated by reference to Exhibit 10 to Form 10-Q for the quarterly period ended September 30, 1997) 29 10.16 Sixth Amendment to Master Credit Support Agreement (incorporated by reference to Exhibit 10.17 to Form 10-K for the year ended December 31, 1997) 10.17 Tenth Amendment to Master Credit Support Agreement (incorporated by reference to Exhibit 10.1 to Form 8-K dated June 1, 1999) 10.18 Eleventh Amendment to Master Credit Support Agreement (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarterly period ended September 30, 1999) 10.19 Amended and Restated Restricted Unit Plan (incorporated by reference to Exhibit 10.18 to Form 10-K for the year ended December 31, 1997) 10.20 Agreement by and between Genesis Crude Oil, L.P. and Bank One, Texas, N.A. dated as of August 14, 1998 (incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarterly period ended September 30, 1998) 10.21 Amendment No. 1 to Loan Agreement by and between Genesis Crude Oil, L.P. and Bank One, Texas, N.A. dated as of August 14, 1998 (incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarterly period ended September 30, 1998) 10.22 Amendment No. 2 to Loan Agreement by and between Genesis Crude Oil, L.P. and Bank One, Texas, N.A. dated as of August 14, 1998 (incorporated by reference to Exhibit 10.21 to Form 10-K for the year ended December 31, 1998) 10.23 Credit Agreement dated as of March 29, 2000, between Genesis Crude Oil, L.P. and Certain Lenders, with Paribas as Agent 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 * 27 Financial Data Schedule ---------------------- * 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 None. 30 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 10th day of October, 2000. 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 October 10, 2000 ----------------------- and President Mark J. Gorman (Principal Executive Officer) /s/ Ross A. Benavides Chief Financial Officer, October 10, 2000 ----------------------- General Counsel and Ross A. Benavides Secretary (Principal Financial and Accounting Officer) /s/ A. Richard Janiak Chairman of the Board and October 10, 2000 ----------------------- Director A. Richard Janiak /s/ Herbert I. Goodman Director October 10, 2000 ----------------------- Herbert I. Goodman /s/ J. Conley Stone Director October 10, 2000 ----------------------- J. Conley Stone /s/ Michael A. Peak Director October 10, 2000 ----------------------- Michael A. Peak /s/ Robert T. Moffett Director October 10, 2000 ----------------------- Robert T. Moffett /s/ John P. vonBerg Vice Chairman, Director, and October 10, 2000 ----------------------- Executive Vice President, Trading John P. vonBerg and Price Risk Management 30 GENESIS ENERGY, L.P. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page ---- Report of Independent Public Accountants 32 Consolidated Balance Sheets, December 31, 1999 and 1998 33 Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998 and 1997 34 Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997 35 Consolidated Statements of Partners' Capital for the Years Ended December 31, 1999, 1998 and 1997 36 Notes to Consolidated Financial Statements 37 32 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, 1999 and 1998 and the related consolidated statements of operations, cash flows and partners' capital for each of the three years in the period ended December 31, 1999. 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, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Houston, Texas March 2, 2000 33 GENESIS ENERGY, L.P. CONSOLIDATED BALANCE SHEETS (In thousands)

December 31, December 31, 1999 1998 -------- -------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 6,664 $ 7,710 Accounts receivable - Trade 241,529 167,600 Related party 7,030 4,634 Inventories 404 1,966 Insurance receivable for pipeline spill costs 16,586 - Other 2,504 3,306 -------- -------- Total current assets 274,717 185,216 FIXED ASSETS, at cost 116,332 119,310 Less: Accumulated depreciation (22,419) (20,707) -------- -------- Net fixed assets 93,913 98,603 OTHER ASSETS, net of amortization 11,962 13,354 -------- -------- TOTAL ASSETS $380,592 $297,173 ======== ======== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Current portion of long-term debt $ 19,900 $ - Accounts payable - Trade 251,742 172,143 Related party 1,604 6,200 Accrued liabilities 19,290 5,171 -------- -------- Total current liabilities 292,536 183,514 LONG-TERM DEBT - 15,800 COMMITMENTS AND CONTINGENCIES (Note 18) ADDITIONAL PARTNERSHIP INTERESTS 3,900 - MINORITY INTERESTS 30,571 29,988 PARTNERS' CAPITAL Common unitholders, 8,625 units issued; 8,620 and 8,604 units outstanding at December 31, 1999 and 1998, respectively 52,574 66,832 General partner 1,051 1,357 -------- -------- Subtotal 53,625 68,189 Treasury units, 5 and 21 units at December 31, 1999 and 1998, respectively (40) (318) -------- -------- Total partners' capital 53,585 67,871 -------- -------- TOTAL LIABILITIES AND PARTNERS' CAPITAL $380,592 $297,173 ======== ========

The accompanying notes are an integral part of these consolidated financial statements. 34 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts)

Year Ended December 31, ------------------------------------- 1999 1998 1997 ---------- ---------- ---------- REVENUES: Gathering and marketing revenues Unrelated parties $2,067,451 $2,178,224 $2,911,333 Related parties 77,195 38,718 443,606 Pipeline revenues 16,366 16,533 17,989 ---------- ---------- ---------- Total revenues 2,161,012 2,233,475 3,372,928 COST OF SALES: Crude costs, unrelated parties 2,043,506 2,141,715 3,147,694 Crude costs, related parties 74,812 42,814 183,490 Field operating costs 11,669 12,778 12,107 Pipeline operating costs 8,161 7,971 6,016 ---------- ---------- ---------- Total cost of sales 2,138,148 2,205,278 3,349,307 ---------- ---------- ---------- GROSS MARGIN 22,864 28,197 23,621 EXPENSES: General and administrative 11,649 11,468 8,557 Depreciation and amortization 8,220 7,719 6,300 Nonrecurring charges - 373 - ---------- ---------- ---------- OPERATING INCOME 2,995 8,637 8,764 OTHER INCOME (EXPENSE): Interest income 156 421 1,190 Interest expense (1,085) (267) (127) Net gain on disposal of surplus assets 849 28 21 ---------- ---------- ---------- Net income before minority interests 2,915 8,819 9,848 Minority interests 583 1,763 1,968 ---------- ---------- ---------- NET INCOME $ 2,332 $ 7,056 $ 7,880 ========== ========== ========== NET INCOME PER COMMON UNIT- BASIC AND DILUTED $ 0.27 $ 0.80 $ 0.90 ========== ========== ========== WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING 8,604 8,606 8,625 ========== ========== ==========

The accompanying notes are an integral part of these consolidated financial statements. 35 GENESIS ENERGY, L.P. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)

Year Ended December 31, 1999 1998 1997 -------- -------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 2,332 $ 7,056 $ 7,880 Adjustments to reconcile net income to net cash provided by (used in) operating activities - Depreciation 6,832 6,529 5,820 Amortization of intangible assets 1,388 1,190 480 (Gain) loss on disposal of assets (849) 269 (21) Minority interests equity in earnings 583 1,763 1,968 Other noncash charges 1,459 1,503 66 Changes in components of working capital - Accounts receivable (76,325) 37,635 178,938 Inventories 1,562 1,384 1,257 Other current assets (15,784) 182 (2,092) Accounts payable 75,003 (39,648) (172,761) Accrued liabilities 13,861 (1,446) (1,330) -------- -------- --------- Net cash provided by operating activities 10,062 16,417 20,205 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment (2,717) (13,431) (5,848) Change in other assets 416 (4,270) (162) Proceeds from sales of assets 1,012 188 348 -------- -------- --------- Net cash used in investing activities (1,289) (17,513) (5,662) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings under Loan Agreement 4,100 15,800 - Distributions to common unitholders (17,206) (17,208) (14,317) Distributions to General Partner (352) (352) (292) Issuance of additional partnership interests 3,900 - - Purchase of treasury units (261) (1,246) - -------- -------- --------- Net cash used in financing activities (9,819) (3,006) (14,609) Net decrease in cash and cash equivalents (1,046) (4,102) (66) Cash and cash equivalents at beginning of period 7,710 11,812 11,878 -------- -------- --------- Cash and cash equivalents at end of period $ 6,664 $ 7,710 $ 11,812 ======== ======== ========= 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 at December 31, 1996 $ 83,378 $1,702 $ - $ 85,080 Net income 7,722 158 - 7,880 Cash distributions (14,317) (292) - (14,609) -------- ------ ------- -------- Partners' capital at December 31, 1997 76,783 1,568 - 78,351 Net income 6,915 141 - 7,056 Cash distributions (17,208) (352) - (17,560) Purchase of treasury units - - (1,246) (1,246) Issuance of treasury units to Restricted Unit Plan participants - - 928 928 Excess of expense over cost of treasury units issued for Restricted Unit Plan 342 - - 342 -------- ------ ------- -------- 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 ======== ====== ======= ======== The accompanying notes are an integral part of these consolidated financial statements.

37 GENESIS ENERGY, L.P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Formation and Offering In December 1996, Genesis Energy, L.P. ("GELP" or the "Partnership") completed an initial public offering of 8.6 million Common Units at $20.625 per unit, representing limited partner interests in GELP of 98%. Genesis Energy, L.L.C. (the "General Partner") serves as general partner of GELP and its operating limited partnership, Genesis Crude Oil, L.P. Genesis Crude Oil, L.P. has two subsidiary limited 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 collectively as GCOLP. The General Partner owns a 2% general partner interest in GELP. Transactions at Formation At the closing of the offering, GELP contributed the net proceeds of the offering ($163.0 million) to GCOLP in exchange for a 80.01% general partner interest in GCOLP. With the net proceeds of the offering, GCOLP purchased for $74.0 million a portion of the crude oil gathering, marketing and pipeline operations of Howell Corporation ("Howell") and made a distribution of $86.9 million to Basis Petroleum, Inc. ("Basis") in exchange for its conveyance of a portion of its crude oil gathering and marketing operations. GCOLP issued an aggregate of 2.2 million subordinated limited partner units ("Subordinated OLP Units") to Basis and Howell to obtain the remaining operations. Basis' Subordinated OLP Units were transferred to its then parent, Salomon Smith Barney Holdings Inc. ("Salomon") in May 1997. The General Partner received an effective 2% general partner interest in GELP in exchange for a contribution of $2.9 million. The effects of these transactions, and the dilutive effect of differences in the consideration paid by the respective parties for their interests, have been reflected in the initial capital recorded by the Partnership. At formation, Basis had the largest ownership interest in the Partnership, with an effective 10.58% limited partner interest in GCOLP and ownership of 54% of the General Partner; therefore, the net assets acquired from Basis were recorded at their historical carrying amounts and the crude oil gathering and marketing division of Basis were treated as the Predecessor and the acquirer of Howell's operations. The acquisition of Howell's operations was treated as a purchase for accounting purposes. 2. Basis of Presentation The accompanying financial statements and related notes present the consolidated financial position as of December 31, 1999 and 1998 for GELP and its results of operations, cash flows and changes in partners' capital for the years ended December 31, 1999, 1998 and 1997. 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. All material intercompany accounts and transactions have been eliminated. 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 99,000 barrels per day at the wellhead principally in the southern and southwestern states. The Partnership also owns and operates three crude oil pipelines onshore. The onshore pipelines are in Texas, Mississippi/Louisiana and Florida/Alabama. 38 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. Inventories Crude oil inventories held for sale are valued at market. Store warehouse inventories, including tractor and trailer parts, supplies and fuel, 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. 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 is being amortized over a period of 20 years. See Note 8. Minority Interests Minority interests represent the Subordinated OLP Units held by Salomon and Howell totaling 19.59% in GCOLP and the 0.4% interest the General Partner owns directly in GCOLP. 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. Hedging Activities The Partnership routinely utilizes forward contracts, swaps, options and futures contracts in an effort to minimize the impact of crude oil price fluctuations on inventories and contractual commitments. Gains and losses related to these hedging activities are deferred until the transaction being hedged has settled and its related profit or loss is recognized. Deferred gains and losses from hedging activities are included in the Consolidated Balance Sheets in accrued liabilities or accounts receivable, respectively. Recognized gains and losses from hedging activities are included in crude costs in the Consolidated Statements of Operations. Unrecognized loss of $1,718,000 and $1,042,000 were deferred on these contracts at December 31, 1999 and 1998, respectively. Based on the historical correlations between the NYMEX price for West Texas intermediate crude at Cushing, Oklahoma, and the various trading hubs at which the Partnership trades, the Partnership's management believes the hedging program has been effective in minimizing the overall price risk. The Partnership continuously monitors the basis (location) differentials between its various trading hubs and Cushing, Oklahoma, to further manage its exposure. 39 Should a hedging contract became ineffective or otherwise cease to serve as a hedge, the hedging instrument is accounted for under the mark-to-market method of accounting. Under this method, the contract is reflected at market value, and the resulting unrealized gains and losses are recognized currently in crude costs in the Consolidated Statements of Operations. 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. 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 8,604,352, 8,605,934 and 8,625,000 for the years ended December 31, 1999, 1998 and 1997, respectively. For this purpose, the 2% General Partner interest 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 November 1998, the Emerging Issues Task Force (EITF) reached a consensus on EITF Issue 98-10, "Accounting for Energy Trading and Risk Management Activities". This consensus, effective in the first quarter of 1999, requires that certain energy related contracts be marked-to-market, with gains or losses recognized in current earnings. The Partnership has determined that its activities do not meet the definition in EITF Issue 98-10 of "energy trading" activities and, therefore, it was not required to make any change in its accounting. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", was issued in June 1998. This standard was subsequently amended by SFAS 137. This new standard, which the Partnership will be required to adopt for its fiscal year 2001, will change the method of accounting for changes in the fair value of certain derivative instruments by requiring that an entity recognize the derivative at fair value as an asset or liability on its balance sheet. Depending on the purpose of the derivative and the item it is hedging, the changes in fair value of the derivative will be recognized in current earnings or as a component of other comprehensive income in partners' capital. The Partnership is in the process of evaluating the impact that this statement will have on its results of operations and financial position. This new standard could increase volatility in net income and comprehensive income. 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. A significant portion of the Partnership's revenues in 1997 resulted from transactions with Basis and other Salomon affiliates. No other customer accounted for more than 10% of the Partnership's revenues in any period. 6. Inventories Inventories consisted of the following (in thousands). December 31, ------------ 1999 1998 ----- ------ Crude oil inventories, at market $ - $1,644 Store warehouse inventories, at lower of cost or market $ 404 $ 322 ----- ------ Total inventories $ 404 $1,966 ===== ====== 40 7. Fixed Assets Fixed assets consisted of the following (in thousands). December 31, -------------------- 1999 1998 -------- -------- Land and buildings $ 3,726 $ 3,489 Pipelines and related assets 95,378 93,796 Vehicles and transportation equipment 5,950 8,006 Office equipment, furniture and fixtures 2,347 5,281 Other 8,931 8,738 116,332 119,310 Less - Accumulated depreciation (22,419) (20,707) -------- -------- Net fixed assets $ 93,913 $ 98,603 ======== ========= Depreciation expense was $6,832,000, $6,529,000 and $5,820,000 for the years ended December 31, 1999, 1998 and 1997, respectively. 8. Other Assets Other assets consisted of the following (in thousands). December 31, ------------------- 1999 1998 -------- ------- Goodwill $ 9,401 $ 9,401 NYMEX seats 1,203 1,203 Covenant not to compete 4,238 4,393 Other 62 66 14,904 15,063 Less - Accumulated amortization (2,942) (1,709) ------- ------- Net other assets $11,962 $13,354 Amortization expense was $1,388,000, $1,190,000 and $480,000 for the years ended December 31, 1999, 1998 and 1997, respectively. 9. Credit Resources and Liquidity GCOLP entered into credit facilities with Salomon (collectively, the "Credit Facilities"), pursuant to a Master Credit Support Agreement. GCOLP's obligations under the Credit Facilities are secured by its receivables, inventories, general intangibles and cash. Guaranty Facility Salomon is providing a Guaranty Facility through December 31, 2000 in connection with the purchase, sale and exchange of crude oil by GCOLP. The aggregate amount of the Guaranty Facility is limited to $300 million for the year ending December 31, 2000 (to be reduced in each case by the amount of any obligation to a third party to the extent that such third party has a prior security interest in the collateral). GCOLP pays a guarantee fee to Salomon which increases over the remaining term thereby increasing the cost of the Guaranty Facility. At December 31, 1999, the aggregate amount of obligations covered by guarantees was $164 million, including $72 million in payable obligations and $92 million of estimated crude oil purchase obligations for January 2000. The Master Credit Support Agreement contains various restrictive and affirmative covenants including (i) restrictions on indebtedness other than (a) pre-existing indebtedness, (b) indebtedness pursuant to Hedging Agreements (as defined in the Master Credit Support Agreement) entered into in the ordinary course of business and (c) indebtedness incurred in the ordinary course of business by acquiring and holding receivables to be collected in accordance with customary trade terms, (ii) restrictions on certain liens, investments, guarantees, loans, advances, lines of business, acquisitions, mergers, consolidations and sales of assets and (iii) compliance with certain risk management policies, audit and receivable risk exposure practices and cash management practices as may from time to time be revised or altered by Salomon in its sole discretion. Pursuant to the Master Credit Support Agreement, GCOLP is required to maintain (a) Consolidated Tangible Net Worth of not less than $50 million, (b) Consolidated Working Capital of not less than $1 million, (c) a ratio of 41 its Consolidated Current Liabilities to Consolidated Working Capital plus net property, plant and equipment of not more than 7.5 to 1, (d) a ratio of Consolidated Earnings before Interest, Taxes, Depreciation and Amortization to Consolidated Fixed Charges of at least 1.75 to 1 as of the last day of each fiscal quarter prior to December 31, 1999 and (e) a ratio of Consolidated Total Liabilities to Consolidated Tangible Net Worth of not more than 10.0 to 1 (as such terms are defined in the Master Credit Support Agreement). The Partnership is currently in compliance with the provisions of this agreement. An Event of Default could result in the termination of the Credit Facilities at the discretion of Salomon. Significant Events of Default include (a) a default in the payment of (i) any principal on any payment obligation under the Credit Facilities when due or (ii) interest or fees or other amounts within two business days of the due date, (b) the guaranty exposure amount exceeding the maximum credit support amount for two consecutive calendar months, (c) failure to perform or otherwise comply with any covenants contained in the Master Credit Support Agreement if such failure continues unremedied for a period of 30 days after written notice thereof and (d) a material misrepresentation in connection with any loan, letter of credit or guarantee issued under the Credit Facilities. Removal of the General Partner will result in the termination of the Credit Facilities and the release of all of Salomon's obligations thereunder. There can be no assurance of the availability or the terms of credit for the Partnership. At this time, Salomon does not intend to provide guarantees or other credit support after the credit support period expires in December 2000. If the General Partner is removed without its consent, Salomon's credit support obligations will terminate. In addition, Salomon's obligations under the Master Credit Support Agreement may be transferred or terminated early subject to certain conditions. Management of the Partnership intends to replace the Guaranty Facility with a letter of credit facility with one or more third party lenders prior to December 2000 and has had preliminary discussions with banks about a replacement letter of credit facility. The General Partner may be required to reduce or restrict the Partnership's gathering and marketing activities because of limitations on its ability to obtain credit support and financing for its working capital needs. The General Partner expects that the overall cost of a replacement facility may be substantially greater than what the Partnership is incurring under its existing Master Credit Support Agreement. 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 or other financial support, make it more difficult for the Partnership to obtain such letters of credit, and/or may increase the cost of obtaining them. 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. Working Capital Facility Until replaced as described below, Salomon provided GCOLP with a Working Capital Facility of up to $50 million, which amount included direct cash advances not to exceed $35 million outstanding at any one time and letters of credit that may be required in the ordinary course of GCOLP's business. In August 1998, GCOLP entered into a revolving credit/loan agreement ("Loan Agreement") with Bank One, Texas, N.A. ("Bank One") to replace the Working Capital Facility that had been provided by Salomon. The Loan Agreement provides for loans or letters of credit in the aggregate not to exceed the greater of $35 million or the Borrowing Base (as defined in the Loan Agreement). Loans will bear interest at a rate chosen by GCOLP which would be one or more of the following: (a) a Floating Base Rate (as defined in the Loan Agreement) that is generally the prevailing prime rate less one percent; (b) a rate based on the Federal Funds Rate plus one and one-half percent or (c) a rate based on LIBOR plus one and one-quarter percent. The Loan Agreement provides for a revolving period until August 14, 2000, with interest to be paid monthly. All loans outstanding on August 14, 2000, are due at that time. The Loan Agreement is collateralized by the accounts receivable and inventory of GCOLP, subject to the terms of an Intercreditor Agreement between Bank One and Salomon. There is no compensating balance requirement under the Loan Agreement. A commitment fee of 0.35% on the available portion of the commitment is provided for in the agreement. Material covenants and restrictions include requirements to maintain a ratio of current assets (as defined in the Loan Agreement) to current liabilities of at least 1:1 and to maintain tangible net worth in GCOLP, as defined in the Loan Agreement, of not less than $65 million. The Partnership is currently in compliance with the provisions of this agreement. 42 At December 31, 1999, the Partnership had $19.9 million of loans outstanding under the Loan Agreement. The Partnership had no letters of credit outstanding at December 31, 1999. At December 31, 1999, $15.1 million was available to be borrowed under the Loan Agreement. Management of the Partnership has entered into discussions with a bank regarding replacement of the Bank One Loan Agreement with a long-term facility. Based upon these discussions, management expects that it will be able to replace the Loan Agreement with a long-term facility subject to similar terms. If the Partnership is unable to complete the replacement agreement noted above, then other options will be pursued, some of which may have terms not as favorable to the Partnership, including increasing costs and pledging additional collateral. While management believes that it will be able to replace the Loan Agreement on a long-term basis prior to its maturity, there can be no assurance that it will be able to do so. 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.) Distributions of Available Cash to the holders of Subordinated OLP Units are subject to the prior rights of holders of Common Units to receive the minimum quarterly distribution ("MQD") for each quarter during the subordination period (which will not end earlier than December 31, 2001) and to receive any arrearages in the distribution of the MQD on the Common Units for prior quarters during the subordination period. MQD is $0.50 per unit. Salomon has committed, subject to certain limitations, to provide total cash distribution support, with respect to quarters ending on or before December 31, 2001, in an amount up to an aggregate of $17.6 million in exchange for Additional Partnership Interests ("APIs"). Salomon's obligation to purchase APIs will end no later than December 31, 2001, with the actual termination subject to the levels of distributions that have been made prior to the termination date. In 1999, the Partnership utilized $3.9 million of the distribution support from Salomon. An additional $2.2 million of distribution support was utilized in February 2000. After the distribution in February 2000, $6.1 million of distribution support has been utilized and $11.5 million remains available through December 31, 2001 or until such amount is fully utilized, whichever comes first. APIs purchased by Salomon are not entitled to cash distributions or voting rights. The APIs will be redeemed if and to the extent that Available Cash for any future quarter exceeds an amount necessary to distribute the MQD on all Common Units and Subordinated OLP Units and to eliminate any arrearages in the MQD on Common Units for prior periods. In addition, 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. GELP has an approximate 80.01% general partner interest in GCOLP. The remainder of GCOLP is held by Salomon, Howell and the General Partner. These interests, reflected in the consolidated financial statements as minority interests, are as follows. Interest in GCOLP ---------- Subordinated limited partner interest held by: Salomon 10.58% Howell 9.01 General partner interest in GCOLP held by the General Partner 0.40 ----- Total minority interests 19.99% ===== The Partnership is managed by the General Partner. Common Units will receive distributions in liquidation in preference to Subordinated OLP Units. See Note 9 for a discussion regarding distributions. 43 Conversion of Subordinated OLP Units There is no established public market for the Subordinated OLP Units. The Subordinated OLP Units will convert into common units of GCOLP ("Common OLP Units") upon the expiration of the subordination period. The subordination period will not end prior to December 31, 2001 and will only end thereafter if GCOLP satisfies certain cash distribution and earnings tests. Subordinated OLP Units that have converted into Common OLP Units will share equally in distributions of Available Cash with the Common Units. Once the Subordinated OLP Units have converted into Common OLP Units, Salomon or Howell may request that these units be redeemed. At such time, pursuant to a Redemption and Registration Rights Agreement, GELP will use its reasonable best efforts to sell the number of Common Units equal to the number of Common OLP Units in GCOLP that are to be redeemed. The proceeds, net of underwriting discount or placement fees from such sale, will be contributed to GCOLP and used to redeem such Common OLP Units. GELP is obligated to pay the expenses incidental to redemption requests, other than underwriting discount or placement fees. The General Partner will have a proportionate percentage of its general partner interest in GCOLP redeemed when Common OLP Units are redeemed in connection with the exercise of the redemption right. 11. Nonrecurring Charge In the second quarter of 1998, the Partnership shut-in its Main Pass pipeline. A charge of $373,000 was recorded, consisting of $109,000 of costs related to the shut-in and a non-cash write-down of the asset of $264,000. 12. 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. Basis was a wholly-owned subsidiary of Salomon until May 1, 1997, when Basis was sold to Valero Energy Corporation. Basis transferred its 54% interest in the general partner and its approximately 1.2 million Subordinated OLP Units to Salomon in conjunction with the sale of Basis. 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, ------------------------- 1999 1998 1997 ------- ------- ------- Sales to affiliates $77,195 $38,718 $443,606 Purchases from affiliates $74,812 $42,814 $183,490 Clearing of Commodities Futures Transactions The Partnership cleared a portion of its commodity futures transactions on the NYMEX through Basis Clearing, Inc., a wholly-owned subsidiary of Basis. In April 1997, Basis Clearing, Inc. ceased its clearing activities for the Partnership. The Partnership paid commissions to Basis Clearing, Inc. of $29,000 in 1997. 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 $16,687,000, $15,428,000 and $14,973,000 for the years ended December 31, 1999, 1998 and 1997, respectively. The Partnership entered into a Corporate Services Agreement with Basis pursuant to which Basis, directly or through its affiliates, provided certain administrative and support services for the benefit of the Partnership. Such services included human resources, tax, accounting, data processing, NYMEX transaction clearing and other similar administrative services. The Partnership no longer receives any services under the Corporate Services Agreement. Charges by Basis under the Corporate Services Agreement during the period in 1997 that Basis was a related party to the Partnership were approximately $100,000 per month. Treasury Services The Partnership entered into a Treasury Management Agreement with Basis. Effective May 1, 1997, Salomon replaced Basis as a party to the Treasury Management Agreement. Under the Treasury Management Agreement, the Partnership invested excess cash with Salomon and earned interest at market rates. At 44 December 31, 1998 and 1997, the Partnership had $9.0 million and $14.0 million in funds, respectively, deposited with Salomon under the Treasury Management Agreement. Such amounts have been classified in the consolidated balance sheets as cash and cash equivalents. For the years ended December 31, 1998 and 1997, the Partnership earned interest of $288,000 and $833,000, respectively, on the investments with Salomon. The Treasury Management Agreement has expired. Credit Facilities As discussed in Note 9, Salomon provides Credit Facilities to the Partnership. For the years ended December 31, 1999, 1998 and 1997, the Partnership paid Salomon $680,000, $578,000 and $730,000, respectively, for guarantee fees under the Credit Facilities. The Partnership paid Salomon $18,000 for interest under the Credit Facilities during 1998. The Partnership paid Basis $85,000 for interest under the Credit Facilities during 1997. 13. Supplemental Cash Flow Information Cash received by the Partnership for interest for the years ended December 31, 1999, 1998 and 1997 was $152,000, $422,000 and $1,139,000, respectively. Payments of interest were $1,035,000, $274,000 and $122,000 for the years ended December 31, 1999, 1998 and 1997, respectively. 14. 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. The General Partner's employees participated in the plans of Basis in 1997. Beginning in 1998, the General Partner maintained its own 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 $566,000, $619,000 and $474,000 for the years ended December 31, 1999, 1998 and 1997, respectively. The General Partner also provided certain health care and survivor benefits for its active employees. In 1998, these plans were fully-insured. In 1999 and 1997, these benefit programs were self-insured. In 2000, these plans will be self-insured. The expenses of the General Partner for these benefits were $1,067,000, $1,338,000 and $1,731,000 in 1999, 1998, 1997, respectively. The General Partner also adopted two plans in January 1997 and amended these plans in January 1998. These plans are a restricted unit plan ("Restricted Unit Plan") for key employees of the General Partner and the Genesis Incentive Compensation Plan ("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. Initially, rights to receive 291,000 Common Units were available under the restricted unit plan with rights to receive 194,000 Common Units allocated to approximately 30 individuals. The restricted units would vest upon the conversion of Subordinated OLP Units to Common OLP Units. In the event of early conversion of a portion of the Subordinated OLP Units into Common OLP Units, the restricted units would vest in the same proportion. The Partnership recorded no compensation expense related to the restricted unit plan in 1997 due to uncertainty as to whether the necessary vesting conditions would be met. Likewise, the restricted units were not considered in diluted net income per common unit in 1997 as none of the vesting conditions had been met in any period. 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 240,000 Common Units (the "Restricted Units") have been allocated to approximately 32 individuals, subject to the vesting conditions described below and subject to other customary terms and conditions. The remaining rights to receive 51,000 Common Units initially available under the Restricted Unit Plan may be allocated or issued in the future to key 45 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 1998, one-third of the Restricted Units allocated to each individual vested and the units issued were acquired on 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. The participant shall receive cash awards based on the number of non-vested units held by such participant to the extent that distributions are paid on Subordinated OLP Units. To date, no distributions have been paid with respect to Subordinated OLP Units. No consideration will be payable by the participants in the Restricted Unit Plan upon vesting and issuance of the Common Units. Additionally, the participant cannot sell the Common Units until one year after the date of vesting. Termination without cause in violation of a written employment agreement, or a Significant Event as defined in the Restricted Unit Plan, will result in immediate vesting of all non-vested units and conversion to Common Units without any restrictions. In 1999 and 1998, the Partnership recorded expense of $1,459,000 and $1,617,000, respectively, related to the Restricted Units. Incentive Plan The Incentive Plan is designed to enhance the financial performance of the Partnership by rewarding the executive officers and other specific key employees for achieving annual financial performance objectives. The Incentive Plan will be administered by the Compensation Committee. Individual participants and payments, if any, for each calendar year will be determined by and in the discretion of the Compensation Committee. No incentive payment will be made with respect to any year unless (i) the aggregate MQD in the Incentive Plan year has been distributed to each holder of Common Units, plus any arrearage thereon, (ii) the Adjusted Operating Surplus generated during such year has equaled or exceeded the sum of the MQD on all of the outstanding Common Units and the related distribution on the General Partner's interest during such year and (iii) no APIs are outstanding. In addition, incentive payments will not exceed $375,000 with respect to any year unless (i) each holder of Subordinated OLP Units has also received the aggregate MQD and (ii) the Adjusted Operating Surplus generated during such year exceed the sum of the MQD on all of the outstanding Common Units and Subordinated OLP Units and the related distribution on the General Partner's interest during such year. Any incentive payments will be at the discretion of the Compensation Committee, and the General Partner will be able to amend or change the Incentive Plan at any time. No incentive payments have been made under the Incentive Plan, although the Compensation Committee has awarded performance bonuses. 15. 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. Changes in the market value of these transactions are deferred until the gain or loss is recognized on the hedged transaction, at which time such gains and losses are recognized through crude costs. 16. 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 New York Mercantile Exchange (NYMEX) is limited due to the daily cash settlement procedures and other NYMEX requirements. 46 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. 17. 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. Estimated fair values of option contracts used as hedges and the net gains and losses, both recognized and deferred, arising from hedging activities at December 31, 1999, 1998 and 1997 are as follows (in thousands).

1999 1998 1997 --------------------- --------------------- --------------------- Net Net Net Carrying Fair Gains Carrying Fair Gains Carrying Fair Gains Amount Value (Losses) Amount Value (Losses) Amount Value (Losses) ------ ----- -------- ------ ----- -------- ------ ----- -------- Option contracts written $390 $390 $ - $ - $ - $ - $1,356 $803 $553

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. 18. Commitments and Contingencies The Partnership uses surface, vehicle and office leases in the course of its business operations. The Partnership also leases a segment of pipeline and four tanks for use in its pipeline operations. The future minimum rental payments under all noncancelable operating leases as of December 31, 1999, were as follows (in thousands). 2000 $1,051 2001 776 2002 672 2003 481 2004 513 2005 and thereafter 448 ------ Total minimum lease obligations $3,941 ====== Total operating lease expense was as follows (in thousands). Year ended December 31, 1999 $1,674 Year ended December 31, 1998 $1,921 Year ended December 31, 1997 $1,060 The Partnership has contractual commitments (primarily forward contracts) arising in the ordinary course of business. At December 31, 1999, the Partnership had commitments to purchase 17,222,000 barrels of crude oil at fixed prices ranging from $14.87 to $27.20 per barrel extending to January 2001, and commitments to sell 17,495,000 barrels of crude oil at fixed prices ranging from $14.60 to $27.25 per barrel extending to February 2001. Additionally, the Partnership had commitments to purchase 28,514,000 barrels of crude oil extending to February 2001, and commitments to sell 13,268,000 barrels of crude oil extending to June 2000, both associated with market-price related contracts. The Partnership is subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance. The Partnership's management has made an assessment of its potential environmental exposure and determined that such exposure is not material to its consolidated financial position, results of operations or cash flows. As part of the formation of the Partnership, Basis 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. 47 The Partnership is subject to lawsuits in the normal course of business and examinations 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. As part of the formation of the Partnership, Basis and Howell agreed to each retain liability and responsibility for the defense of any future lawsuits arising out of activities conducted by Basis and Howell prior to the formation of the Partnership and have also agreed to cooperate in the defense of such lawsuits. Pipeline 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. The oil then flowed into the Leaf River. The Partnership responded to this incident immediately, deploying crews to evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill had been substantially cleaned up, with ongoing maintenance and reduced clean-up activity expected to continue for several more months. The estimated cost of the spill clean-up is expected to be $17 million. A final determination as to the cause of the spill has not been completed. The incident was reported to insurers, and incurred costs related to the clean-up efforts have been reimbursed or approved for reimbursement by the insurers. The insurers, however, have reserved the right to claim the return of the insurance proceeds should the final determination of cause be a cause not covered by the insurance policies. Based on its review of the policies and its understanding of the facts associated with the spill, management of the General Partner believes that the costs of the spill are covered by insurance and collection of the receivable is probable. In its 1999 financial statements, the Partnership charged to expense the deductible of $50,000 and recorded a liability for $17 million, which includes estimates for clean-up costs, ongoing maintenance related to the clean-up and settlement of claims of potential liabilities to landowners in connection with the spill. The Partnership recorded a receivable from the insurance company for the insurance proceeds. The receivable is included in "Insurance receivable for pipeline spill costs." Included in accounts payable is $1.0 million related to vendor invoices received and $15.0 million for estimated amounts to be incurred for the spill. $1.0 million had already been paid at December 31, 1999. Should the ultimate determination of the cause of the spill prove not to be covered by insurance, the Partnership will be required to write off the receivable of $17 million. As a result of this crude oil spill, certain federal and state regulatory agencies may impose fines and penalties that would not be reimbursed by insurance. At this time, it is not possible to predict whether the Partnership will be fined, the amounts of such fines, or whether such governmental agencies would prevail in imposing such fines. The segment of the Mississippi System where the spill occurred has been temporarily shut down and will not be returned to service until regulators give their approval. Regulatory authorities may require specific testing or changes to the pipeline before allowing the Partnership to restart that segment of the system. At this time, it is unknown whether there will be any required testing or changes and the related cost of that testing or changes. If the costs of testing or changes are too high, that segment of the system may not be restarted. If this part of the Mississippi System is taken out of service, annual tariff revenues would be reduced by approximately $0.6 million and the net book value of that portion of the pipeline would be written down to its net realizable value, resulting in a non-cash write-off of approximately $6.0 million. 19. Subsequent Event On February 28, 2000, Howell sold its 46% interest in the General Partner to Salomon Brothers Holding Company Inc.